AltaGas (ATGFF) 40-F 28 Feb 20 2019 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2019shares
Document And Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	AltaGas Ltd.
Entity Central Index Key	0001695519
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding	279,074,685
Entity Interactive Data Current	Yes

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents (note 31)	$ 57.1	$ 101.6
Accounts receivable, net of allowances (note 23)	1,222.4	1,547.5
Inventory (note 7)	505.6	515.9
Restricted cash holdings from customers (note 31)	4	4.1
Regulatory assets (note 21)	12.8	21
Risk management assets (note 23)	86.6	114.1
Prepaid expenses and other current assets (notes 28 and 31)	280.2	199.9
Assets held for sale (note 5)	27.5	1,528.9
Total current assets	2,196.2	4,033
Property, plant and equipment (note 8)	10,125.5	10,929.6
Intangible assets (note 9)	585.6	711.9
Operating right-of-use assets (note 10)	169.8
Goodwill (note 11)	3,942.1	4,068.2
Regulatory assets (note 21)	486.7	663
Risk management assets (note 23)	39.1	57.7
Restricted cash holdings from customers (note 31)	3.9	6.1
Prepaid post-retirement benefits (note 28)	487.5	342.7
Long-term investments and other assets (notes 12, 28, and 31)	296.5	283.1
Investments accounted for by the equity method (note 14)	1,461.6	2,392.4
Total assets	19,794.5	23,487.7
Current liabilities
Accounts payable and accrued liabilities (notes 17, 18, 23, and 28)	1,324.9	1,488.2
Dividends payable (note 23)	22.3	22
Short-term debt (notes 15 and 23)	460	1,209.9
Current portion of long-term debt (notes 16 and 23)	922.9	890.2
Customer deposits	76.6	98
Regulatory liabilities (note 21)	145.5	114.9
Risk management liabilities (note 23)	124.8	89.3
Operating lease liabilities (note 10)	27.3
Other current liabilities (note 23)	17	18.1
Liabilities associated with assets held for sale (note 5)	3.8	171.4
Total current liabilities	3,125.1	4,102
Long-term debt (notes 16 and 23)	5,927.8	8,066.9
Asset retirement obligations (note 17)	362	500.6
Unamortized investment tax credits (note 20)	3.8	190.1
Deferred income taxes (note 20)	959.1	957.9
Regulatory liabilities (note 21)	1,383.2	1,392.8
Risk management liabilities (note 23)	167	213
Operating lease liabilities (note 10)	153.4
Other long-term liabilities (notes 19 and 23)	101.8	122
Future employee obligations (note 28)	242.5	302.2
Total liabilities	12,425.7	15,847.5
Shareholders' equity
Common shares, no par values, unlimited shares authorized; 2019 - 279.1 million and 2018 - 275.2 million issued and outstanding (note 25)	6,719	6,653.9
Preferred shares (note 25)	1,277.1	1,318.8
Contributed surplus	376.7	373.2
Accumulated deficit	(1,402.8)	(1,905.3)
Accumulated other comprehensive income (AOCI) (note 22)	244.9	579
Total shareholders' equity	7,214.9	7,019.6
Non-controlling interests	153.9	620.6
Total equity	7,368.8	7,640.2
Total liabilities and shareholders' equity	$ 19,794.5	$ 23,487.7

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares shares in Millions	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common shares issued (shares)	279.1	275.2
Common shares outstanding (shares)	279.1	275.2

Consolidated Statements of Inco

Consolidated Statements of Income (Loss) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Statement [Abstract]
REVENUE (note 24)	$ 5,495	$ 4,256.7
EXPENSES
Cost of sales, exclusive of items shown separately	3,227.1	2,455.3
Operating and administrative	1,298.7	1,129
Accretion expenses (note 17)	5.1	10.9
Depreciation and amortization (notes 8 and 9)	438	394
Provisions on assets (note 6)	415.8	728.7
Total expenses	5,384.7	4,717.9
Income from equity investments (note 14)	141.1	47.9
Other income (note 27)	908.1	0.9
Foreign exchange gains (losses)	(1)	4.5
Interest expense	(345.8)	(309)
Income (loss) before income taxes	812.7	(716.9)
Income tax expense (recovery) (note 20)
Current	63.3	24.4
Deferred	(90.9)	(287.6)
Net income (loss) after taxes	840.3	(453.7)
Net income (loss) applicable to non-controlling interests	6.8	(18.6)
Net income (loss) applicable to controlling interests	833.5	(435.1)
Preferred share dividends	(68.5)	(66.6)
Gain on redemption of preferred shares (note 25)	3.5	0
Net income (loss) applicable to common shares	$ 768.5	$ (501.7)
Net income (loss) per common share (note 26)
Basic (per share)	$ 2.78	$ (2.25)
Diluted (per share)	$ 2.77	$ (2.25)
Weighted average number of common shares outstanding (millions) (note 26)
Basic (shares)	276.9	222.6
Diluted (shares)	277.4	222.6

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss) after taxes	$ 840.3	$ (453.7)
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	(406.2)	458.5
Unrealized gain (loss) on net investment hedge (note 23)	60	(80.2)
Actuarial gain (loss) on pension plans and post-retirement benefit (PRB) plans (note 28)	12	(10.8)
Reclassification of actuarial gains and prior service credits on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28)	0.8	0.5
Curtailment of DB and PRB plan (note 28)	0	2.7
Adoption of ASU 2016-01	0	7.1
Other comprehensive income (loss) from equity investees	(0.7)	2.1
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(334.1)	379.9
Comprehensive income (loss) attributable to controlling interests and non-controlling interests, net of taxes	506.2	(73.8)
Comprehensive income (loss) attributable to:
Non-controlling interests	6.8	(18.6)
Controlling interests	$ 499.4	$ (55.2)

Consolidated Statements of Equi

Consolidated Statements of Equity - CAD ($) $ in Millions		Total	Total shareholders' equity	Common shares (note 25)	Preferred shares (note 25)	Contributed surplus	Accumulated deficit	AOCI (note 22)	Non-controlling interests
Net Income (Loss) Attributable to Parent		$ (435.1)
Balance, beginning of year at Dec. 31, 2017				$ 4,007.9	$ 1,277.7	$ 22.3	$ (933.6)	$ 199.1	$ 65.8
Increase (Decrease) in Stockholders' Equity
Exercise of share options				1.3		(0.1)
Shares issued under DRIP	[1]			325.8
Deferred taxes on share issuance costs				13.3
Shares issued on conversion of subscription receipts, net of issuance costs				2,305.6
Shares acquired through WGL Acquisition					41.1				9
Share options expense						0.9
Forfeiture of share options						(0.1)
Sale of non-controlling interest						350.2			498.4
Net income (loss) applicable to controlling interests		(453.7)					(435.1)		(18.6)
Common share dividends							(462.9)
Preferred share dividends							(66.6)
Gain on redemption of preferred shares		0
Other comprehensive income (loss)		379.9						379.9
Contributions from non-controlling interests to subsidiaries									96.3
Distributions by subsidiaries to non-controlling interests									(30.3)
Balance, end of year at Dec. 31, 2018		7,640.2	$ 7,019.6	6,653.9	1,318.8	373.2	(1,905.3)	579	620.6
Net Income (Loss) Attributable to Parent		833.5					833.5
Increase (Decrease) in Stockholders' Equity
Exercise of share options				1.2		(0.1)
Shares issued under DRIP	[1]			67.8
Deferred taxes on share issuance costs				(3.9)	(0.6)
Redemption of WGL preferred shares					(41.1)
Share options expense						3.7
Forfeiture of share options						(0.1)
Net income (loss) applicable to controlling interests		840.3							6.8
Common share dividends							(266)
Preferred share dividends							(68.5)
Gain on redemption of preferred shares		3.5					3.5
Other comprehensive income (loss)		(334.1)						(334.1)
Adjustment on disposition of assets									(508)
Contributions from non-controlling interests to subsidiaries									47.9
Distributions by subsidiaries to non-controlling interests									(13.4)
Balance, end of year at Dec. 31, 2019		$ 7,368.8	$ 7,214.9	$ 6,719	$ 1,277.1	$ 376.7	$ (1,402.8)	$ 244.9	$ 153.9
[1]	Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash from (used by) operations
Net income (loss) after taxes	$ 840.3	$ (453.7)
Items not involving cash:
Depreciation and amortization	438	394
Provisions on assets (note 6)	415.8	728.7
Accretion expenses	5.1	10.9
Share-based compensation (note 25)	3.5	0.8
Deferred income tax recovery (note 20)	(90.9)	(287.6)
Losses (gains) on sale of assets (notes 4 and 27)	(875.8)	10.6
Income from equity investments (note 14)	(141.1)	(47.9)
Unrealized losses (gains) on risk management contracts (note 23)	85.3	(80.8)
Realized loss on expiry of foreign exchange options	0	36
Losses on investments (note 27)	4.1	10.1
Amortization of deferred financing costs	11.5	29.7
Provision for doubtful accounts	26.7	17
Net change in pension and other post-retirement benefits (note 28)	8.1	(3.8)
Other	9.2	3.6
Asset retirement obligations settled (note 17)	(2.5)	(4.2)
Distributions from equity investments	109.7	44.5
Changes in operating assets and liabilities (note 31)	(231.5)	(486.5)
Net cash provided (required) by operating activities	615.5	(78.6)
Investing activities
Business acquisitions, net of cash acquired	0	(5,931)
Acquisition of property, plant and equipment	(1,296.8)	(990.4)
Acquisition of intangible assets	(37.7)	(38.1)
Contributions to equity investments	(178.7)	(235.4)
Loan to affiliate, net of repayment (note 30)	0	30
Financing receivable	0	(8.7)
Proceeds from disposition of investments	0	76.5
Proceeds from initial public offering of AltaGas Canada Inc.	0	858.9
Proceeds from disposition of assets, net of transaction costs (note 4)	3,623.4	403.8
Proceeds from disposition of financing receivable (note 4)	73.5	0
Net cash provided (required) by investing activities	2,183.7	(5,834.4)
Financing activities
Net issuance (repayment) of short-term debt	(700.9)
Net issuance (repayment) of short-term debt		497.7
Issuance of long-term debt, net of debt issuance costs	888.6	1,851.9
Repayment of long-term debt	(873.3)	(278.8)
Net borrowing (repayment) under credit facilities	(1,919.7)	846.2
Dividends - common shares	(265.7)	(472.9)
Dividends - preferred shares	(68.5)	(66.6)
Distributions to non-controlling interest	(13.4)	(30.3)
Contributions from non-controlling interests	47.9	96.3
Net proceeds from shares issued on exercise of options	1.1	1.2
Net proceeds from issuance of common shares	67.8	2,633.7
Redemption of preferred shares (note 25)	(37.6)	0
Net proceeds from sale of non-controlling interest	0	908.6
Net cash provided (required) by financing activities	(2,873.7)	5,987
Change in cash, cash equivalents, and restricted cash	(74.5)	74
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(9.1)	7.3
Net change in cash classified within assets held for sale	4.9	(4.9)
Restricted cash acquired (note 31)	0	81
Cash, cash equivalents, and restricted cash beginning of year	201.1	43.7
Cash, cash equivalents, and restricted cash end of year (note 31)	$ 122.4	$ 201.1

Organization and Overview of th

Organization and Overview of the Business	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Overview of the Business	Organization and Overview of the Business The businesses of AltaGas are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., WGL Holdings, Inc. (WGL), Wrangler 1 LLC, Wrangler SPE LLC, Washington Gas Resources Corporation, WGL Energy Services, Inc. (WGL Energy Services), and SEMCO Holding Corporation; in regards to the Midstream business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership, Harmattan Gas Processing Limited Partnership, Ridley Island LPG Export Limited Partnership, and WGL Midstream Inc. (WGL Midstream); in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe); and, in regards to the Utilities business, Washington Gas Light Company (Washington Gas), Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas), its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR) and its 65 percent interest in an Alaska regulated gas storage utility under the name Cook Inlet Natural Gas Storage Alaska LLC (CINGSA). AltaGas, a Canadian corporation, is a leading North American energy infrastructure company that connects natural gas liquids (NGLs) and natural gas to domestic and global markets. The Corporation’s long-term strategy is to grow in attractive areas across its Utilities and Midstream business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off the West Coast of Canada via the Corporation’s footprint in the Montney region. In the Utilities business, the Corporation seeks to grow through rate base investment and the use of accelerated rate recovery programs, while providing effective and cost-efficient service for customers. AltaGas has three business segments: § Utilities, which serves approximately 1.7 million customers with a rate base of approximately US $3.9 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services; § Midstream, which includes a 70 percent interest in the recently completed Ridley Island Propane Export Terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada including natural gas gathering and processing, NGL extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States, WGL’s retail gas marketing business, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP) , and an indirectly held approximate one-third ownership investment in Petrogas Energy Corp. (Petrogas) , through which AltaGas’ interest in the Ferndale terminal is held; and § Power, which includes 710 MW of operational capacity from natural gas-fired, distributed generation, and energy storage assets, certain of which are pending sale, located in Alberta, Canada and the United States, primarily in California and Colorado. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies BASIS OF PRESENTATION These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). Pursuant to National Instrument 52‑107, "Acceptable Accounting Principles and Auditing Standards" (NI 52‑107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On July 13, 2018, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP. PRINCIPLES OF CONSOLIDATION These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence, but not control, over are accounted for using the equity method. Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain equity method investments as well as consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage. The majority of AltaGas' HLBV investments were sold during 2019. All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non‑controlling interest in a subsidiary that AltaGas controls, that non‑controlling interest is reflected as “non‑controlling interests” in the Consolidated Financial Statements. The non‑controlling interests in net income (or loss) of consolidated subsidiaries are shown as an allocation of the consolidated net income (loss) and are presented separately in "net income (loss) applicable to non‑controlling interests". USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates; determination as to whether a contract is or contains a lease; determination of the classification, term, and discount rate for leases; fair value of asset retirement obligations; fair value of property, plant and equipment and goodwill for impairment assessments; fair value of financial instruments; provisions for income taxes; assumptions used to measure employee future benefits; provisions for contingencies; purchase price allocations; and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods. SIGNIFICANT ACCOUNTING POLICIES Rate-Regulated Operations SEMCO Gas, ENSTAR, Washington Gas, and Hampshire Gas (collectively the Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia, and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD), and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively. Hampshire is regulated under a cost-of-service tariff by the Federal Energy Regulatory Commission (FERC). The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting, and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues, and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation. Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process. Cash and Cash Equivalents Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months. Restricted Cash Holdings from Customers Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain Washington Gas executive and outside director retirement benefit plan obligations. The rabbi trust funds are invested in money market funds which are considered cash equivalents. These balances are included in "prepaid expenses and other current assets" and "long-term investments and other assets" in the Consolidated Balance Sheets. Accounts Receivable Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. Inventory Inventory consists of materials, supplies, natural gas, natural gas liquids, renewable energy credits, and emission compliance instruments which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas. Property, Plant, and Equipment (PP&E), Depreciation and Amortization Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight-line basis over the estimated useful life of the assets, with the exception of rate-regulated utilities assets, for which depreciation is calculated on a straight-line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities. The Utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs. Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas' prior quarter actual borrowing long-term interest rate. The Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate-regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses, and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators. The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 4 to 69 years Midstream assets 2 to 45 years Power generation assets 3 to 46 years Corporate assets 3 to 7 years As required by the regulatory authority, net additions to SEMCO's utility assets are amortized for one half-year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month after they are brought into active service. Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statements of Income (Loss) . Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statements of Income (Loss) . Intangible Assets Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 to 19 years Electricity service agreements 2 to 60 years Software 3 to 10 years Land rights 5 to 64 years Franchises and consents 9 to 25 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 to 20 years The intangible assets recorded in the purchase price allocation for certain WGL commodity contracts are amortized based on the estimated fair value of the deliveries over the term of the contracts, which are over a period of 20 years . Assets Held for Sale The Corporation classifies assets as held for sale when the carrying amount will be principally recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized. Business Acquisitions Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired. Management applies its best estimates and assumptions to determine the fair value of net assets acquired; however, the estimates are subject to further refinement of assumptions over a measurement period, which may be up to one year from the acquisition date. During the measurement period, adjustments to assets acquired and liabilities assumed may be recorded, with a corresponding impact to goodwill. Provisions on Assets If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized. Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the fair value of the reporting unit will be compared to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its fair value and an impairment loss would be recorded in the Consolidated Statements of Income (Loss) . Investments Accounted for by the Equity Method The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period. The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity's book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period. An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statements of Income (Loss) . Financial Instruments Non-Utility Operations All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as "held-for-trading", "held-to-maturity", or "loans and receivables". Financial liabilities are classified as "held-for-trading" or other financial liabilities. Subsequent measurement is determined by classification. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Held-for-trading instruments include non-derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards, and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees. Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statements of Income (Loss) under " other income ". Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative, and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings. The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred. Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under "long-term investments and other assets" on the Consolidated Balance Sheets. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statements of Income (Loss) . Regulated Utility Operations All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income. Transaction costs for obtaining debt financing and reacquired debt costs are recorded as regulatory assets or liabilities, or as a reduction of the debt liability on the Consolidated Balance Sheets. Weather-Related Instruments WGL purchases certain weather-related instruments, such as heating degree day (HDD) derivatives and cooling degree day (CDD) derivatives to manage weather and price risks related to its natural gas and electricity sales. These derivatives are accounted for in accordance with ASC 815-45, Derivatives and Hedging – Weather Derivatives. For HDD derivatives, gains or losses are recognized when the actual HDD’s falls above or below the contractual HDD’s for each instrument. For CDD derivatives, gains or losses are recognized when the average temperature exceeds or is below a contractually stated level during the contract period. Refer to Note 23 for further discussion on weather-related instruments. Hedges As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate, and foreign exchange risk. AltaGas has designated certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815. Non-Utility Operations The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs. Regulated Utility Operations During planned issuances of debt securities, Washington Gas may utilize derivative instruments to manage the risk of interest-rate volatility. Gains and losses associated with these types of derivatives are recorded as regulatory liabilities or assets, and amortized in accordance with regulatory requirements, typically over the life of the related debt. Debt AltaGas uses short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Short-term obligations are excluded from current liabilities if AltaGas has the ability and the intent to refinance these obligations on a long-term basis. The ability to refinance is primarily demonstrated through the availability of long-term revolving committed credit facilities in an amount equal to or greater than the expected maximum short-term obligation. Asset Retirement Obligations AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations. There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates, as allowed by the regulators. These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980. Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators. Revenue Recognition AltaGas has revenue from various sources, including rate-regulated revenue, commodity sales, midstream service contracts, gas sales and transportation services, and gas storage services. For a detailed description of the Corporation’s revenue recognition policy by major source of revenue, please refer to Note 24 . Foreign Currency Translation Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statements of Income (Loss) . Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date. For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI. AltaGas may designate some of its U.S. dollar denominated long-term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long-term debt are included in OCI. Share Options and Other Compensation Plans Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity. AltaGas has a phantom unit plan (Phantom Plan, formerly the medium-term incentive plan) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas' common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash. The other portion of RU’s and PUs are valued at US $1 per unit. Upon vesting, the RUs and PUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2.4 dependent on the Corporation's performance relative to performance targets as approved by the Board of Directors. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs. In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers, and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers, and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, the participant is entitled to payment upon retirement, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs. Pension Plans and Post-Retirement Benefits AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs. The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees, expected health care costs, and other actuarial factors including discount rates and mortality. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs and credits are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 9.0 years and 13.2 years , respectively. AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability. For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. Income Taxes Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed, and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities. Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties. The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future. Net Income (Loss) per Share Basic net income (loss) per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards. The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change. Leases The following are the Corporation’s significant accounting policies upon the adoption of ASC 842: Leases – Lessee AltaGas determines if an arrangement is a lease at inception. Operating leases are included in right-of-use (ROU) assets, current operating lease liabilities, and long-term operating lease liabilities in the Consolidated Balance Sheets. Finance leases are included in property, plant and equipment and current and long-term debt in the Consolidated Balance Sheets. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. AltaGas uses the rate implicit in the lease when readily determinable. When the implicit lease rate is not readily determinable, AltaGas uses its incremental borrowing rate to determine the present value of lease payments. AltaGas includes lessee options to renew or terminate the lease term in the determination of the ROU asset and lease liability when exercise is reasonably certain. The operat

Acquisition of WGL Holdings, In

Acquisition of WGL Holdings, Inc.	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisition of WGL Holdings, Inc.	Acquisition of WGL Holdings, Inc. Following the receipt of all required federal, state, and local regulatory approvals, on July 6, 2018 the Corporation acquired WGL. The WGL Acquisition was accounted for as a business combination using the acquisition method of accounting whereby the acquired assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The following table summarizes the final purchase price allocation representing the consideration paid and the fair value of the net assets acquired as at July 6, 2018 using an exchange rate of 1.31 to convert U.S. dollars to Canadian dollars. The purchase price allocation was finalized on June 30, 2019 and reflects Management’s best estimate of the fair value of WGL’s assets and liabilities. In the first half of 2019, based on new information obtained in the period and further refinement of assumptions, adjustments to the purchase price allocation included amounts relating to intangible assets, deferred income taxes, pension liabilities, current liabilities, other long-term liabilities, valuation of equity investments in Midstream pipelines, and deferred rent, resulting in a net increase to goodwill of approximately $92.2 million (Note 11 ). Purchase consideration $ 5,973 Fair value assigned to net assets Current assets $ 1,220 Property, plant and equipment 5,884 Intangible assets 577 Regulatory assets 408 Long-term investments 1,475 Other long-term assets 462 Current liabilities (1,916 ) Long-term debt (2,548 ) Preferred shares (41 ) Regulatory liabilities (1,126 ) Deferred income taxes (741 ) Other long-term liabilities (959 ) Non-controlling interest (9 ) Accumulated other comprehensive income (2 ) Fair value of net assets acquired $ 2,684 Goodwill $ 3,289

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Dispositions	Dispositions Northwest Hydro Electric Facilities On January 31, 2019 , AltaGas completed the disposition of its remaining 55 percent indirect interest in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro) for net cash proceeds of approximately $1.3 billion . The disposition was completed through the sale of 55 percent of Northwest Hydro Limited Partnership, a subsidiary of AltaGas which indirectly held the Northwest Hydro facilities. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $687.6 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . Non-Core Midstream and Power Assets in Canada On February 1, 2019 , AltaGas completed the disposition of certain non-core Midstream and Power assets for gross cash proceeds of approximately $87.8 million . As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.2 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . Architect of the Capitol (AOC) Project In February 2019 , AltaGas completed the disposition of a financing receivable related to the construction of an energy management services project for gross cash proceeds of approximately $73.5 million . As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.3 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . Stonewall Gas Gathering System On May 31, 2019 , AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall Gas Gathering System (Stonewall) to a wholly-owned subsidiary of DTE Energy Company for gross cash proceeds of approximately $379.2 million ( US$280 million ). As a result, AltaGas recognized a pre-tax gain on disposition of $34.1 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . Biomass Assets On August 13, 2019 , AltaGas completed the disposition of its equity ownership interests in Craven County Wood Energy LP and Grayling Generation Station LP for net proceeds of approximately $24.5 million ( US$18.5 million ). There was no gain or loss resulting from this disposition. Distributed Generation Assets On September 26, 2019 , AltaGas closed the disposition of its portfolio of U.S. distributed generation assets for gross cash proceeds of approximately $975.0 million ( US$735.0 million ). As a result, AltaGas recognized a pre-tax gain on disposition of approximately $167.5 million in the Consolidated Statements of Income (Loss) under the line item " other income " for the year ended December 31, 2019 . There are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities relating to these projects remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2019 (Note 5 ). The portion of the purchase price relating to these projects is approximately $32.2 million (US $24.8 million ) and is recorded within "accounts payable and accrued liabilities" on the Consolidated Balance Sheets until these projects are legally transferred to the purchaser. The pre-tax gain related to these remaining projects has also been deferred and will be recognized as these projects are legally transferred. The purchaser is entitled to after-tax earnings from the distributed generation projects, including those awaiting consent, beginning September 1, 2019. Capital Spare In the third quarter of 2019 , AltaGas completed the sale of a capital spare turbine in the Power segment for gross cash proceeds of $4.6 million ( US$3.5 million ). There was no gain or loss resulting from this disposition in the year ended December 31, 2019 . Investment in Meade On November 13, 2019 , AltaGas completed the disposition of its investment in Meade Pipeline Co. LLC (Meade) which held WGL Midstream's indirect, non-operating interest in the Central Penn pipeline (Central Penn), for cash proceeds of approximately $811.5 million ( US$610.8 million ). As a result, AltaGas recognized a pre-tax loss on disposition of $11.1 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . During 2019, AltaGas also recognized a pre-tax provision of $44.2 million against AltaGas' investment in Meade Pipeline Co. LLC (Note 14). Assets Held For Sale As at December 31, 2019 December 31, 2018 Assets held for sale Cash $ — $ 4.9 Accounts receivable — 85.2 Inventory — 0.5 Property, plant and equipment 22.9 1,189.6 Intangible assets — 248.7 Operating right-of-use assets 0.4 — Goodwill 1.0 — Other long-term assets 3.2 — $ 27.5 $ 1,528.9 Liabilities associated with assets held for sale Accounts payable and accrued liabilities $ — $ 23.8 Asset retirement obligations 0.2 10.8 Unamortized investment tax credits 3.2 — Operating lease liabilities - long-term 0.4 — Other long-term liabilities — 136.8 $ 3.8 $ 171.4 Distributed Generation Assets In September 2019, AltaGas closed the sale of its portfolio of U.S. distributed generation assets (Note 4 ). However, there are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities related to these projects remain classified as held for sale at December 31, 2019. These assets are recorded in the Power segment.

Assets Held For Sale

Assets Held For Sale	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Assets Held For Sale	Dispositions Northwest Hydro Electric Facilities On January 31, 2019 , AltaGas completed the disposition of its remaining 55 percent indirect interest in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro) for net cash proceeds of approximately $1.3 billion . The disposition was completed through the sale of 55 percent of Northwest Hydro Limited Partnership, a subsidiary of AltaGas which indirectly held the Northwest Hydro facilities. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $687.6 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . Non-Core Midstream and Power Assets in Canada On February 1, 2019 , AltaGas completed the disposition of certain non-core Midstream and Power assets for gross cash proceeds of approximately $87.8 million . As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.2 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . Architect of the Capitol (AOC) Project In February 2019 , AltaGas completed the disposition of a financing receivable related to the construction of an energy management services project for gross cash proceeds of approximately $73.5 million . As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.3 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . Stonewall Gas Gathering System On May 31, 2019 , AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall Gas Gathering System (Stonewall) to a wholly-owned subsidiary of DTE Energy Company for gross cash proceeds of approximately $379.2 million ( US$280 million ). As a result, AltaGas recognized a pre-tax gain on disposition of $34.1 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . Biomass Assets On August 13, 2019 , AltaGas completed the disposition of its equity ownership interests in Craven County Wood Energy LP and Grayling Generation Station LP for net proceeds of approximately $24.5 million ( US$18.5 million ). There was no gain or loss resulting from this disposition. Distributed Generation Assets On September 26, 2019 , AltaGas closed the disposition of its portfolio of U.S. distributed generation assets for gross cash proceeds of approximately $975.0 million ( US$735.0 million ). As a result, AltaGas recognized a pre-tax gain on disposition of approximately $167.5 million in the Consolidated Statements of Income (Loss) under the line item " other income " for the year ended December 31, 2019 . There are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities relating to these projects remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2019 (Note 5 ). The portion of the purchase price relating to these projects is approximately $32.2 million (US $24.8 million ) and is recorded within "accounts payable and accrued liabilities" on the Consolidated Balance Sheets until these projects are legally transferred to the purchaser. The pre-tax gain related to these remaining projects has also been deferred and will be recognized as these projects are legally transferred. The purchaser is entitled to after-tax earnings from the distributed generation projects, including those awaiting consent, beginning September 1, 2019. Capital Spare In the third quarter of 2019 , AltaGas completed the sale of a capital spare turbine in the Power segment for gross cash proceeds of $4.6 million ( US$3.5 million ). There was no gain or loss resulting from this disposition in the year ended December 31, 2019 . Investment in Meade On November 13, 2019 , AltaGas completed the disposition of its investment in Meade Pipeline Co. LLC (Meade) which held WGL Midstream's indirect, non-operating interest in the Central Penn pipeline (Central Penn), for cash proceeds of approximately $811.5 million ( US$610.8 million ). As a result, AltaGas recognized a pre-tax loss on disposition of $11.1 million in the Consolidated Statements of Income (Loss) under the line item “ other income ” for the year ended December 31, 2019 . During 2019, AltaGas also recognized a pre-tax provision of $44.2 million against AltaGas' investment in Meade Pipeline Co. LLC (Note 14). Assets Held For Sale As at December 31, 2019 December 31, 2018 Assets held for sale Cash $ — $ 4.9 Accounts receivable — 85.2 Inventory — 0.5 Property, plant and equipment 22.9 1,189.6 Intangible assets — 248.7 Operating right-of-use assets 0.4 — Goodwill 1.0 — Other long-term assets 3.2 — $ 27.5 $ 1,528.9 Liabilities associated with assets held for sale Accounts payable and accrued liabilities $ — $ 23.8 Asset retirement obligations 0.2 10.8 Unamortized investment tax credits 3.2 — Operating lease liabilities - long-term 0.4 — Other long-term liabilities — 136.8 $ 3.8 $ 171.4 Distributed Generation Assets In September 2019, AltaGas closed the sale of its portfolio of U.S. distributed generation assets (Note 4 ). However, there are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities related to these projects remain classified as held for sale at December 31, 2019. These assets are recorded in the Power segment.

Provisions on Assets

Provisions on Assets	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Provisions on Assets	Provisions on Assets Year Ended December 31 2019 2018 Utilities $ — $ 193.7 Midstream 35.2 153.7 Power 380.6 381.3 $ 415.8 $ 728.7 Utilities There were no provisions recorded in the Utilities segment in 2019 . In 2018 , AltaGas recorded pre-tax provisions of $193.7 million related to certain rate-regulated natural gas distributed utility assets that were classified as held for sale in the third quarter of 2018. Midstream In 2019 , AltaGas recorded pre-tax provisions of $35.2 million related to the Pouce Coupe sour gas treatment facility in Alberta. The pre-tax provisions were comprised of $35.0 million on property, plant and equipment and $0.2 million on intangible assets. In 2018 , AltaGas recorded pre-tax provisions of $153.7 million related to certain non-core Midstream assets that were classified as held for sale at December 31, 2018 and shut-in assets in the South, Cold Lake and Northwest operating areas. Power In 2019 , AltaGas recorded pre-tax provisions totaling $380.6 million in the Power segment. The pre-tax provisions were recorded against property, plant and equipment. In 2018 , AltaGas recorded pre-tax provisions of $381.3 million primarily related to the Tracy, Hanford, and Henrietta gas-fired peaking plants in California that were disposed of in the fourth quarter of 2018, a development project in the U.S., the Pomona natural gas-fired co-generation facility in the United States, and non-core Power assets in Canada and a WGL Energy Systems financing receivable that were classified as held for sale at December 31, 2018.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Inventory	Inventory As at December 31 2019 2018 Natural gas held in storage (a) $ 359.0 $ 418.0 Materials and supplies 56.3 53.3 Renewable energy credits and emission compliance instruments 64.1 38.2 Natural gas liquids 26.2 6.4 $ 505.6 $ 515.9 (a) As at December 31, 2019 , $214.3 million of the natural gas held in storage was held by rate-regulated utilities ( 2018 - $270.4 million ).

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment As at December 31, 2019 December 31, 2018 Cost Accumulated Net book Cost Accumulated Net book Utilities $ 7,316.1 $ (155.0 ) $ 7,161.1 $ 7,090.5 $ (89.7 ) $ 7,000.8 Midstream 3,182.0 (585.4 ) 2,596.6 3,178.2 (845.7 ) 2,332.5 Power 976.7 (594.6 ) 382.1 4,633.9 (1,858.3 ) 2,775.6 Corporate 49.5 (40.9 ) 8.6 49.4 (39.1 ) 10.3 Reclassified to assets held for sale (25.2 ) 2.3 (22.9 ) (2,999.3 ) 1,809.7 (1,189.6 ) $ 11,499.1 $ (1,373.6 ) $ 10,125.5 $ 11,952.7 $ (1,023.1 ) $ 10,929.6 Interest capitalized on long-term capital construction projects for the year ended December 31, 2019 was $14.5 million ( 2018 - $12.6 million ). As at December 31, 2019 , the Corporation had approximately $725.2 million ( December 31, 2018 - $872.7 million ) of capital projects under construction that were not yet subject to amortization. Depreciation expense related to property, plant and equipment (including assets under capital leases) for the year ended December 31, 2019 was $357.8 million ( 2018 - $324.3 million ).

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible Assets As at December 31, 2019 December 31, 2018 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26.6 $ (15.2 ) $ 11.4 $ 26.6 $ (14.3 ) $ 12.3 Electricity service agreements 8.5 (7.8 ) 0.7 269.5 (25.9 ) 243.6 Energy services relationships 91.6 (27.4 ) 64.2 176.1 (33.8 ) 142.3 Software 303.7 (101.2 ) 202.5 293.9 (77.7 ) 216.2 Land rights 1.1 (0.1 ) 1.0 1.4 (0.2 ) 1.2 Commodity contracts 327.1 (21.3 ) 305.8 346.3 (6.3 ) 340.0 Franchises and consents — — — 5.0 — 5.0 Reclassified to assets held for sale (note 5) — — — (277.4 ) 28.7 (248.7 ) $ 758.6 $ (173.0 ) $ 585.6 $ 841.4 $ (129.5 ) $ 711.9 Amortization expense related to intangible assets for the year ended December 31, 2019 was 80.2 million ( 2018 - $69.7 million ). As at December 31, 2019 , the Corporation excluded $184.5 million ( December 31, 2018 - $196.4 million ) from the asset base subject to amortization. Items excluded relate to gas transportation capacity contracts, software assets under development, and assets with an indefinite life. The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with an indefinite life, for the years ended December 31: 2020 $ 79.1 2021 $ 70.6 2022 $ 69.7 2023 $ 62.3 2024 $ 24.2 Thereafter $ 95.2

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Leases Lessee AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, vehicles, power and gas facilities, transmission and distribution assets, and land. The components of lease expense were as follows: Year Ended Operating lease cost (includes variable lease payments) $ 29.2 Finance lease cost Amortization of right-of-use assets $ 3.4 Interest on lease liabilities 0.3 Total finance lease cost $ 3.7 Total lease cost $ 32.9 Supplemental cash flow information related to leases was as follows: Year Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from finance leases $ (0.3 ) Operating cash flows from operating leases $ (20.6 ) Financing cash flows from finance leases (a) $ (3.7 ) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 50.4 Finance leases $ 5.4 (a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows. Supplemental balance sheet information related to leases was as follows: As at December 31, 2019 Operating Leases Operating lease right-of-use assets Long-term $ 169.8 Included in assets held for sale (note 5) 0.4 Total operating lease right-of-use assets $ 170.2 Operating lease liabilities Current $ (27.3 ) Long-term (153.4 ) Included in liabilities associated with assets held for sale (note 5) (0.4 ) Total operating lease liabilities $ (181.1 ) Finance Leases Property and equipment, gross $ 13.2 Accumulated depreciation (3.3 ) Property and equipment, net $ 9.9 Current portion of long-term debt $ (3.5 ) Long-term debt (6.4 ) Total finance lease liabilities $ (9.9 ) As at December 31, 2019 Weighted average remaining lease term (years) Operating leases 10.9 Finance leases 5.2 Weighted average discount rate (%) Operating leases 3.51 Finance leases 3.68 Maturity analysis of lease liabilities was as follows: Operating Leases Finance Leases 2020 $ 27.8 $ 3.5 2021 27.1 2.9 2022 26.5 2.0 2023 24.5 1.1 2024 20.1 0.4 Thereafter 100.1 2.0 Total lease payments 226.1 11.9 Less: imputed interest (45.0 ) (2.0 ) Total $ 181.1 $ 9.9 As of December 31, 2019 , AltaGas has additional operating leases, primarily for rail cars, that have not yet commenced of $4.8 million . These operating leases will commence in 2020 with lease terms of up to 6 years . Lessor Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. Maturity analysis of lease receivables was as follows: Operating Leases 2020 $ 118.3 2021 115.4 2022 115.6 2023 115.9 2024 47.8 Thereafter 477.5 Total $ 990.5 The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2019 . AltaGas manages its risk associated with the residual value of its leased assets through strategically constructing leased facilities in key commercial regions and retaining the ability to sell commodities and ancillary services via the merchant market or through commodity sales agreements.
Leases	Leases Lessee AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, vehicles, power and gas facilities, transmission and distribution assets, and land. The components of lease expense were as follows: Year Ended Operating lease cost (includes variable lease payments) $ 29.2 Finance lease cost Amortization of right-of-use assets $ 3.4 Interest on lease liabilities 0.3 Total finance lease cost $ 3.7 Total lease cost $ 32.9 Supplemental cash flow information related to leases was as follows: Year Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from finance leases $ (0.3 ) Operating cash flows from operating leases $ (20.6 ) Financing cash flows from finance leases (a) $ (3.7 ) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 50.4 Finance leases $ 5.4 (a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows. Supplemental balance sheet information related to leases was as follows: As at December 31, 2019 Operating Leases Operating lease right-of-use assets Long-term $ 169.8 Included in assets held for sale (note 5) 0.4 Total operating lease right-of-use assets $ 170.2 Operating lease liabilities Current $ (27.3 ) Long-term (153.4 ) Included in liabilities associated with assets held for sale (note 5) (0.4 ) Total operating lease liabilities $ (181.1 ) Finance Leases Property and equipment, gross $ 13.2 Accumulated depreciation (3.3 ) Property and equipment, net $ 9.9 Current portion of long-term debt $ (3.5 ) Long-term debt (6.4 ) Total finance lease liabilities $ (9.9 ) As at December 31, 2019 Weighted average remaining lease term (years) Operating leases 10.9 Finance leases 5.2 Weighted average discount rate (%) Operating leases 3.51 Finance leases 3.68 Maturity analysis of lease liabilities was as follows: Operating Leases Finance Leases 2020 $ 27.8 $ 3.5 2021 27.1 2.9 2022 26.5 2.0 2023 24.5 1.1 2024 20.1 0.4 Thereafter 100.1 2.0 Total lease payments 226.1 11.9 Less: imputed interest (45.0 ) (2.0 ) Total $ 181.1 $ 9.9 As of December 31, 2019 , AltaGas has additional operating leases, primarily for rail cars, that have not yet commenced of $4.8 million . These operating leases will commence in 2020 with lease terms of up to 6 years . Lessor Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. Maturity analysis of lease receivables was as follows: Operating Leases 2020 $ 118.3 2021 115.4 2022 115.6 2023 115.9 2024 47.8 Thereafter 477.5 Total $ 990.5 The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2019 . AltaGas manages its risk associated with the residual value of its leased assets through strategically constructing leased facilities in key commercial regions and retaining the ability to sell commodities and ancillary services via the merchant market or through commodity sales agreements.
Leases	Leases Lessee AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, vehicles, power and gas facilities, transmission and distribution assets, and land. The components of lease expense were as follows: Year Ended Operating lease cost (includes variable lease payments) $ 29.2 Finance lease cost Amortization of right-of-use assets $ 3.4 Interest on lease liabilities 0.3 Total finance lease cost $ 3.7 Total lease cost $ 32.9 Supplemental cash flow information related to leases was as follows: Year Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from finance leases $ (0.3 ) Operating cash flows from operating leases $ (20.6 ) Financing cash flows from finance leases (a) $ (3.7 ) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 50.4 Finance leases $ 5.4 (a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows. Supplemental balance sheet information related to leases was as follows: As at December 31, 2019 Operating Leases Operating lease right-of-use assets Long-term $ 169.8 Included in assets held for sale (note 5) 0.4 Total operating lease right-of-use assets $ 170.2 Operating lease liabilities Current $ (27.3 ) Long-term (153.4 ) Included in liabilities associated with assets held for sale (note 5) (0.4 ) Total operating lease liabilities $ (181.1 ) Finance Leases Property and equipment, gross $ 13.2 Accumulated depreciation (3.3 ) Property and equipment, net $ 9.9 Current portion of long-term debt $ (3.5 ) Long-term debt (6.4 ) Total finance lease liabilities $ (9.9 ) As at December 31, 2019 Weighted average remaining lease term (years) Operating leases 10.9 Finance leases 5.2 Weighted average discount rate (%) Operating leases 3.51 Finance leases 3.68 Maturity analysis of lease liabilities was as follows: Operating Leases Finance Leases 2020 $ 27.8 $ 3.5 2021 27.1 2.9 2022 26.5 2.0 2023 24.5 1.1 2024 20.1 0.4 Thereafter 100.1 2.0 Total lease payments 226.1 11.9 Less: imputed interest (45.0 ) (2.0 ) Total $ 181.1 $ 9.9 As of December 31, 2019 , AltaGas has additional operating leases, primarily for rail cars, that have not yet commenced of $4.8 million . These operating leases will commence in 2020 with lease terms of up to 6 years . Lessor Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. Maturity analysis of lease receivables was as follows: Operating Leases 2020 $ 118.3 2021 115.4 2022 115.6 2023 115.9 2024 47.8 Thereafter 477.5 Total $ 990.5 The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2019 . AltaGas manages its risk associated with the residual value of its leased assets through strategically constructing leased facilities in key commercial regions and retaining the ability to sell commodities and ancillary services via the merchant market or through commodity sales agreements.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill As at December 31, December 31, Balance, beginning of year $ 4,068.2 $ 817.3 Provisions on assets — (124.2 ) Business acquisition (note 3) — 3,196.4 Adjustment to goodwill on business acquisition (note 3) 92.2 — Goodwill included in dispositions (note 4) (29.1 ) — Reclassified to assets held for sale (note 5) (1.0 ) — Foreign exchange translation (188.2 ) 178.7 Balance, end of year $ 3,942.1 $ 4,068.2

Long-Term Investments and Other

Long-Term Investments and Other Assets	12 Months Ended
	Dec. 31, 2019
Investments, All Other Investments [Abstract]
Long-Term Investments and Other Assets	Long-Term Investments and Other Assets As at December 31, December 31, Investments in publicly-traded entities $ 4.3 $ 8.4 Loan to affiliate 45.0 45.0 Deferred lease receivable 17.4 24.4 Debt issuance costs associated with credit facilities 6.2 7.9 Refundable deposits 8.9 16.2 Prepayment on long-term service agreements 80.6 82.5 Cash calls from joint venture partners 9.5 — Contract asset (note 24) 30.0 11.5 Rabbi trust (notes 28 and 31) 32.0 61.7 Other long-term receivables (note 29) 33.1 — Other 29.5 25.5 $ 296.5 $ 283.1

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2019
VARIABLE INTEREST ENTITIES [Abstract]
Variable Interest Entities	Variable Interest Entities Consolidated VIEs AltaGas consolidates VIEs where the Corporation is deemed the primary beneficiary. The primary beneficiary of a VIE has the power to direct the activities of the entity that most significantly impact its economic performance such as being the provider of construction, operating and marketing services to the entity. In addition, the primary beneficiary of a VIE also has the obligation to absorb losses of the entity or the right to receive benefits that could potentially be significant to the VIE. AltaGas determined that it is the primary beneficiary of the following VIEs: Ridley Island LPG Export Limited Partnership On May 5, 2017, AltaGas LPG Limited Partnership (AltaGas LPG), a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke Vopak N.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed the Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own and operate the Ridley Island Propane Export Terminal (RIPET). AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET was funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries provide operating services to RILE LP. AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the operating and marketing services provided to RILE LP. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP. The assets of RILE LP are the property of RILE LP and are not available to AltaGas for any other purpose. RILE LP’s asset balances can only be used to settle its own obligations. The liabilities of RILE LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. AltaGas and Royal Vopak have provided limited guarantees for the obligations of their respective subsidiaries for the construction cost of RIPET. With the commencement of commercial operations at RIPET, the terms of the long-term capacity agreement between AltaGas LPG and RILE LP provide for a return on and of capital and reimbursement of RIPET's operating costs by AltaGas LPG in accordance with the terms set out in the agreement. Disposal of Consolidated VIE Investments Prior to the close of the U.S. distributed generation asset sale in the third quarter of 2019, a subsidiary of WGL was the primary beneficiary of SFGF LLC, SFRC LLC, SFGF II LLC, SFEE LLC, and ASD Solar LP, because of its ability to direct the activities most significant to the economic performance of those entities plus the right to receive potentially significant benefits or the obligation to absorb potentially significant losses. These VIEs were consolidated until the close of the distributed generation asset sale (Note 4 ). As at December 31, 2019 , these entities are no longer VIEs of AltaGas. The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs: As at December 31, 2019 December 31, 2018 Current assets $ 6.4 $ 1,383.5 Property, plant and equipment 371.1 619.2 Long-term investments and other assets 53.3 48.0 Operating right-of-use assets 0.1 — Current liabilities (3.6 ) (161.8 ) Asset retirement obligations (3.3 ) (0.9 ) Other long-term liabilities (0.1 ) (3.0 ) Net assets $ 423.9 $ 1,885.0 The decrease in current assets, property, plant and equipment, and current liabilities associated with AltaGas’ consolidated VIEs as at December 31, 2019 compared to December 31, 2018 is primarily due to the sale of Northwest Hydro Limited Partnership in January 2019 and the sale of VIEs included in the sale of WGL's distributed generation portfolio (Note 4 ). Disposal of Unconsolidated VIE Investments Prior to the sale of AltaGas' investment in Meade and indirect, non-operating interest in Central Penn (Note 4 ), WGL Midstream owned a 55 percent interest in Meade ( 21 percent indirect interest in Central Penn). Although WGL Midstream held a greater than 50 percent interest in Meade, Meade was not consolidated by WGL Midstream and instead was accounted for under the equity method of accounting. WGL Midstream was not the primary beneficiary of Meade as it did not have the power to direct the activities most significant to the economic performance of Meade. WGL Midstream applied the HLBV equity method of accounting and any profits and losses were included in " income from equity investments " in the accompanying Consolidated Statements of Income (Loss) and were added to or subtracted from the carrying amount of AltaGas' investment balance until the close of the Meade sale. As at December 31, 2019 , Meade is no longer a VIE of AltaGas.

Investments Accounted for by th

Investments Accounted for by the Equity Method	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Investments Accounted for by the Equity Method	Investments Accounted for by the Equity Method Carrying value as at December 31 Equity income (loss) for the year ended December 31 Description Location Ownership Percentage 2019 2018 2019 2018 AltaGas Canada Inc. (ACI) (a) Canada 37 $ 163.9 $ 112.5 $ 17.0 $ 5.4 AltaGas Idemitsu Joint Venture LP Canada 50 431.3 342.9 62.5 2.1 Constitution Pipeline, LLC (Constitution) (b) United States 10 0.1 — (0.5 ) (0.2 ) Craven County Wood Energy LP (c) United States 50 — 7.8 0.1 (14.1 ) Eaton Rapids Gas Storage System United States 50 27.0 29.4 1.3 2.0 Grayling Generating Station LP (c) United States 50 — 29.0 0.3 3.6 Inuvik Gas Ltd. (d) Canada 33 — — — (0.2 ) Meade Pipeline Co. LLC (c) (e) United States 55 — 757.8 (3.6 ) 12.2 Mountain Valley Pipeline, LLC (Mountain Valley) (f) United States 10 671.3 532.5 42.8 11.5 Sarnia Airport Storage Pool LP Canada 50 18.0 18.7 1.0 1.0 Petrogas Preferred Shares Canada n/a 150.0 150.0 12.8 12.8 Stonewall Gas Gathering Systems LLC (c) United States 30 — 411.8 7.4 11.8 $ 1,461.6 $ 2,392.4 $ 141.1 $ 47.9 (a) As at December 31, 2019 , the aggregate market value of AltaGas' investment in ACI was $367.9 million ( 11,025,000 shares at the quoted closing market price of $33.37 on December 31, 2019 ). As at December 31, 2018 , the aggregate market value was $178.8 million ( 11,025,000 shares at the quoted closing market price of $16.22 on December 31, 2018 ). (b) The equity method is considered appropriate because Constitution is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. In February 2020, the partners of Constitution elected not to proceed with the pipeline project (Note 33). (c) Disposed of in 2019 (Note 4 ). (d) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018. (e) Meade was a VIE prior to disposition in November 2019 (Notes 4 and 13 ). (f) The equity method is considered appropriate because Mountain Valley is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. The carrying amount of certain equity investments differs from the amount of the underlying equity in net assets. These basis differences include amounts related to purchase accounting adjustments, capitalized interest, and a contractual cap on contributions to Mountain Valley. Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows (a) : Year Ended December 31 2019 2018 Revenues $ 1,109.3 $ 351.6 Expenses (355.0 ) (142.7 ) $ 754.3 $ 208.9 As at December 31 2019 2018 Current assets $ 411.1 $ 1,204.6 Property, plant and equipment $ 8,033.8 $ 7,602.5 Intangible assets $ 21.9 $ 22.9 Long-term investments and other assets $ 1,458.8 $ 1,326.6 Current liabilities $ (393.8 ) $ (1,015.2 ) Other long-term liabilities $ (992.1 ) $ (949.6 ) (a) For equity investments that were disposed of in the year (Note 4 ), revenues and expenses reflect the period prior to disposition and balance sheet amounts as at December 31 are $nil. Provisions on investments accounted for by the equity method During the year ended December 31, 2019 , AltaGas recorded a pre-tax provision of $44.2 million against AltaGas' investment in Meade Pipeline Co. LLC as a result of the sale of WGL Midstream's interest in Central Penn. The disposition of the investment in this entity was completed in the fourth quarter of 2019 (Note 4 ). This equity investment was in the Midstream segment and the provision was recorded in the Consolidated Statements of Income (Loss) under the line item " income from equity investments ". In addition, during the year ended December 31, 2019 , AltaGas recorded a pre-tax provision of $2.2 million against AltaGas' investment in Craven County Wood Energy LP as a result of a pending sale. The disposition of the investment in this entity was completed in the third quarter of 2019 (Note 4 ). This equity investment was in the Power segment and the provision was recorded in the Consolidated Statements of Income (Loss) under the line item " income from equity investments ". During the year ended December 31, 2018 , AltaGas recorded a pre-tax provision of $14.5 million against AltaGas' investment in Craven Wood County Energy LP. AltaGas Canada Inc. On October 21, 2019 , ACI announced that the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board (together, the "Consortium") and ACI had concluded a definitive arrangement agreement (the "Arrangement Agreement") whereby the Consortium will indirectly acquire all of the issued and outstanding common shares of ACI (the "Common Shares") in an all-cash transaction for $33.50 per Common Share by way of arrangement under the Canada Business Corporations Act (the "Arrangement") . On December 19, 2019, the shareholders of ACI approved the Arrangement Agreement. In addition, on December 16, 2019, ACI received a "no-action letter" from the Canadian Competition Bureau confirming that the Commissioner of Competition does not at this time intend to challenge the proposed Arrangement . On December 20, 2019, ACI received the final order from the Court of Queen's Bench of Alberta approving the Arrangement. On February 18, 2020, the Alberta Utilities Commission issued a decision approving the Arrangement. The closing of the Arrangement remains subject to the receipt of approval from the British Columbia Utilities Commission, and the satisfaction or waiver of other customary closing conditions. ACI and the Consortium expect to close the Arrangement in the first half of 2020.

Short-term Debt

Short-term Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Short-term Debt	Short-term Debt As at December 31, December 31, Bank indebtedness $ — $ 0.2 Commercial paper (a) 389.0 1,145.2 Project financing 71.0 64.5 $ 460.0 $ 1,209.9 (a) WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. As at December 31, 2019, certain commercial paper balances have been classified as long-term debt as they are supported by long-term extendible committed credit facilities with maturities ranging from 2022 to 2024 (see Note 16 ). Project Financing WGL and certain of its subsidiaries previously obtained third-party project financing on behalf of the United States federal government to provide funds for the construction of certain energy management services projects entered into under Washington Gas' area-wide contract. When these projects are formally accepted by the government and deemed complete, the ownership of the receivable is assigned to the third-party lender in satisfaction of the obligation, removing both the receivable and the obligation related to the financing from the Consolidated Financial Statements. As at December 31, 2019 , draws related to project financing were $71.0 million ( December 31, 2018 - $64.5 million ). Other Credit Facilities As at December 31, 2019 , the Corporation held a $70.0 million ( December 31, 2018 - $70.0 million ) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender's prime rate or at the bankers' acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2019 were $ nil ( December 31, 2018 - $ nil ). As at December 31, 2019 , AltaGas held a $150.0 million ( December 31, 2018 - $150.0 million ) unsecured four -year extendible revolving letter of credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. Letters of credit outstanding under this facility as at December 31, 2019 were $25.5 million ( December 31, 2018 - $117.0 million ). As at December 31, 2019 , AltaGas held a US $200.0 million ( December 31, 2018 - US $200.0 million ) unsecured bilateral letter of credit demand facility with a Canadian chartered bank. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding under this facility as at December 31, 2019 were $156.4 million ( December 31, 2018 - $147.3 million ). As at December 31, 2019 , AltaGas held a US $300.0 million ( December 31, 2018 - US $300.0 million ) unsecured extendible revolving letter of credit facility. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding on this facility as at December 31, 2019 were $124.6 million ( December 31, 2018 - $ nil ). WGL and Washington Gas use short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. As at December 31, 2019 , commercial paper outstanding classified as short-term debt totaled US $299.5 million (December 31, 2018 - US $839.5 million ).

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt As at Maturity date December 31, December 31, Credit facilities $1,400 million unsecured extendible revolving facility (a) 15-May-2023 $ 89.6 $ 964.7 US$300 million unsecured extendible revolving facility (b) 15-May-2022 — 287.8 Acquisition credit facility (c) 6-Jan-2020 — 113.2 US$1,200 million unsecured revolving credit facility (d) 28-Dec-2021 — 1,637.0 US$300 million unsecured term facility 27-Feb-2021 389.6 — US$150 million unsecured extendible revolving facility 20-Dec-2023 163.5 — Commercial paper (e) Various 367.4 — AltaGas Ltd. medium-term notes (MTNs) $200 million Senior unsecured - 4.55 percent 17-Jan-2019 — 200.0 $200 million Senior unsecured - 4.07 percent 1-Jun-2020 200.0 200.0 $350 million Senior unsecured - 3.72 percent 28-Sep-2021 350.0 350.0 $500 million Senior unsecured - 2.61 percent 16-Dec-2022 500.0 — $300 million Senior unsecured - 3.57 percent 12-Jun-2023 300.0 300.0 $200 million Senior unsecured - 4.40 percent 15-Mar-2024 200.0 200.0 $300 million Senior unsecured - 3.84 percent 15-Jan-2025 300.0 299.9 $350 million Senior unsecured - 4.12 percent 7-Apr-2026 349.9 349.8 $200 million Senior unsecured - 3.98 percent 4-Oct-2027 199.9 199.9 $100 million Senior unsecured - 5.16 percent 13-Jan-2044 100.0 100.0 $300 million Senior unsecured - 4.50 percent 15-Aug-2044 299.8 299.8 $250 million Senior unsecured - 4.99 percent 4-Oct-2047 250.0 250.0 WGL and Washington Gas MTNs US$450 million Senior unsecured - 2.25 to 4.76 percent (f) Nov 2019 — 682.1 US$250 million Senior unsecured - 2.44 percent (g) 12-Mar-2020 324.7 341.1 US$20 million Senior unsecured - 6.65 percent 20-Mar-2023 26.0 27.3 US$40.5 million Senior unsecured - 5.44 percent 11-Aug-2025 52.6 55.3 US$53 million Senior unsecured - 6.62 to 6.82 percent Oct - 2026 68.8 72.3 US$72 million Senior unsecured - 6.40 to 6.57 percent Feb - Sep 2027 93.5 98.2 US$52 million Senior unsecured - 6.57 to 6.85 percent Jan - Mar 2028 67.5 70.9 US$8.5 million Senior unsecured - 7.50 percent 1-Apr-2030 11.0 11.6 US$50 million Senior unsecured - 5.70 to 5.78 percent Jan - Mar 2036 64.9 68.2 US$75 million Senior unsecured - 5.21 percent 3-Dec-2040 97.4 102.3 US$75 million Senior unsecured - 5.00 percent 15-Dec-2043 97.4 102.3 US$300 million Senior unsecured - 4.22 to 4.60 percent Sep - Dec 2044 389.6 409.3 US$450 million Senior unsecured - 3.80 percent 15-Sep-2046 584.5 613.9 US$300 million Senior unsecured - 3.65 percent 16-Sep-2049 389.6 — SEMCO long-term debt US$300 million SEMCO Senior Secured - 5.15 percent (h) 21-Apr-2020 389.6 409.3 US$82 million SEMCO Senior Secured - 4.48 percent (i) 2-Mar-2032 76.1 86.3 Fair value adjustment on WGL Acquisition (note 3) 84.3 89.0 Finance lease liabilities (note 10) 9.9 0.8 $ 6,887.1 $ 8,992.3 Less debt issuance costs (36.4 ) (35.2 ) $ 6,850.7 $ 8,957.1 Less current portion (922.9 ) (890.2 ) $ 5,927.8 $ 8,066.9 (a) Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers' acceptances, or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made. (b) Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, LIBOR loans, or letters of credit. (c) The acquisition facility was repaid in full and canceled on February 1, 2019. (d) Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, or LIBOR loans. (e) Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024 . (f) Certain MTNs have a floating rate per annum reset quarterly based on terms set forth in the prospectus supplement filed by WGL pursuant to Securities Act Rule 424 on November 27, 2017. (g) Floating rate per annum reset quarterly based on terms set forth in the prospectus filed by WGL pursuant to Securities Act Rule 424 on March 13, 2018. (h) Collateral for the U.S. dollar MTNs is certain SEMCO assets. (i) Collateral for the CINGSA Senior secured loan is certain CINGSA assets. Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan. Other Credit Facilities As at December 31, 2019 , WGL held a US $250.0 million ( December 31, 2018 - US $650.0 million ) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2019 or December 31, 2018 . As at December 31, 2019 , Washington Gas held a US $450.0 million ( December 31, 2018 - US $350.0 million ) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2019 or December 31, 2018 . WGL and Washington Gas use short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. As at December 31, 2019 , outstanding commercial paper classified as long-term debt totaled US$ 283.5 million ( December 31, 2018 - $ nil ).

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations As at December 31 2019 2018 Balance, beginning of year $ 500.6 $ 88.3 Obligations acquired (note 3) — 399.1 New obligations 7.0 3.3 Obligations settled (2.5 ) (4.2 ) Disposals (6.2 ) (1.6 ) Revision in estimated cash flow (128.5 ) 3.8 Accretion expense (a) 18.9 12.3 Foreign exchange translation (20.7 ) 20.3 Reclassified to liabilities associated with assets held for sale (note 5) (0.2 ) (10.8 ) Total $ 368.4 $ 510.5 Less current portion (included in accounts payable and accrued liabilities) (6.4 ) (9.9 ) Balance, end of year $ 362.0 $ 500.6 (a) Certain amounts relating to Utility asset retirement obligations are recorded through regulatory assets or liabilities on the Consolidated Balance Sheets due to regulatory treatment. The remaining portion is recorded through the Consolidated Statements of Income (Loss) . The majority of the asset retirement obligations are associated with distribution and transmission systems in the Utilities segment. AltaGas estimates the undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation, at December 31, 2019 was $727.0 million ( December 31, 2018 - $770.0 million ). The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 2.0 and 8.5 percent (December 31, 2018 - between 1.5 to 8.5 percent ) and are expected to be incurred between 2020 and 2137 (December 31, 2018 - between 2019 and 2064). No assets have been legally restricted for settlement of the estimated liability.

Environmental Matters

Environmental Matters	12 Months Ended
	Dec. 31, 2019
Environmental Remediation Obligations [Abstract]
Environmental Matters	Environmental Matters AltaGas is subject to federal, provincial, state and local laws and regulations related to environmental matters. These laws and regulations may require expenditures over a long time frame to control environmental effects. Almost all of the environmental liabilities AltaGas has recorded are for costs expected to be incurred to remediate sites where AltaGas or a predecessor affiliate operated manufactured gas plants (MGPs). Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following: ▪ the complexity of the site; ▪ changes in environmental laws and regulations at the federal, state, and local levels; ▪ the number of regulatory agencies or other parties involved; ▪ new technology that renders previous technology obsolete or experience with existing technology that proves ineffective; ▪ the level of remediation required; and ▪ variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site. AltaGas has identified up to twelve sites where it or its predecessors may have operated MGPs. In connection with these operations, AltaGas is aware that coal tar and certain other by-products of the gas manufacturing process are present at or near some former sites and may be present at others. As at December 31, 2019 , a liability of $13.8 million has been recorded on an undiscounted basis related to future environmental response costs ( December 31, 2018 - $15.4 million ) in the Consolidated Balance Sheets under the line items “accounts payable and accrued liabilities and other long-term liabilities”. These estimates principally include the minimum liabilities associated with a range of environmental response costs expected to be incurred. As at December 31, 2019 , AltaGas estimated the maximum liability associated with all of its sites to be approximately $39.9 million ( December 31, 2018 - $40.1 million ). The estimates were determined by AltaGas’ environmental experts, based on experience in remediating MGP sites and advice from legal counsel and environmental consultants. The variation between the recorded and estimated maximum liability primarily results from differences in the number of years that will be required to perform environmental response processes and the extent of remediation that may be required. As at December 31, 2019 , AltaGas reported a regulatory asset of $17.7 million ( December 31, 2018 - $19.9 million ) for the portion of environmental response costs that are expected to be recoverable in future rates (Note 21).

Other Long-term Liabilities

Other Long-term Liabilities	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Other Long-term Liabilities	Other Long-term Liabilities As at December 31, December 31, Deferred lease payable $ — $ 13.1 Deferred revenue 4.0 3.9 Customer advances for construction 63.9 58.6 Sundance B PPAs termination expense (a) — 2.0 Lease inducement — 2.7 Merger commitments 14.0 21.4 Other long-term liabilities 19.9 20.3 $ 101.8 $ 122.0 (a) In 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B Power Purchase Arrangements (PPAs). Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which has been recorded under “accounts payable and accrued liabilities”.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Year Ended December 31 2019 2018 Income (loss) before income taxes - consolidated $ 812.7 $ (716.9 ) Statutory income tax rate (%) 26.5 27.0 Expected taxes at statutory rates $ 215.4 $ (193.6 ) Add (deduct) the tax effect of: Permanent differences $ 10.9 $ (1.0 ) Statutory and other rate differences (51.6 ) (19.6 ) Rate adjustment for change in tax rates (10.7 ) 1.3 Deferred income tax recovery on regulated assets (24.8 ) (7.3 ) Tax differences on divestitures and transactions (158.2 ) (32.3 ) Non-controlling interests 3.5 4.7 Change in valuation allowance (11.1 ) (22.3 ) Other (1.0 ) 6.9 $ (27.6 ) $ (263.2 ) Income tax provision Current Canada $ 26.7 $ 23.7 United States 36.6 0.7 $ 63.3 $ 24.4 Deferred Canada $ 11.6 $ (166.1 ) United States (102.5 ) (121.5 ) $ (90.9 ) $ (287.6 ) Effective income tax rate (%) (3.4 ) 36.7 Net deferred income tax liabilities were composed of the following: As at December 31, December 31, PP&E and intangible assets $ 1,450.6 $ 1,764.6 Regulatory assets (204.1 ) (166.3 ) Tax pools, deferred financing, and compensation (138.2 ) (453.6 ) Other (161.2 ) (209.9 ) Valuation allowance 12.0 23.1 $ 959.1 $ 957.9 The amount shown on the Consolidated Balance Sheets as deferred income tax liabilities represents the net differences between the tax basis and book carrying values on the Corporation's balance sheets at enacted tax rates. The Alberta government passed the Job Creation Tax Cut in 2019 which reduced Alberta's corporate tax rate from 12 percent to 11 percent on July 1, 2019. The tax rate will further be reduced from 11 percent to 10 percent on January 1, 2020 and by 1 percent each year until 2022. The rate from 2022 onwards will ultimately be 8 percent . The B.C. government increased the corporate tax rate to 12 percent from 11 percent beginning in 2018. As at December 31, 2019 , the Corporation had tax-effected non-capital losses of approximately $170.4 million , which will be available to offset future taxable income. If not used, these losses will expire between 2024 and 2039 . Uncertain Tax Positions The Corporation recognizes the benefit of an uncertain tax position only when it is more likely than not that such a position will be sustained by the taxing authorities based on the technical merits of the position. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that has greater than 50 percent likelihood of being realized upon settlement with the taxing authorities. On an annual basis, the Corporation and its subsidiaries file tax returns in Canada and various foreign jurisdictions. In Canada, AltaGas' federal and provincial tax returns for the years 2012 to 2018 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns filed for the years 2013 to 2018 remain subject to examination by the taxation authorities. Management determined that the following provision was required for uncertainty on income taxes during the year: Year Ended December 31 2019 2018 Balance, beginning of year $ 2.2 $ 5.9 Net changes during the year (0.2 ) (3.7 ) Balance, end of year $ 2.0 $ 2.2

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities AltaGas accounts for certain transactions in accordance with ASC 980, Regulated Operations. AltaGas refers to this accounting guidance for regulated entities as “regulatory accounting”. Under regulatory accounting, utilities are permitted to defer expenses and income as regulatory assets and liabilities, respectively, in the Consolidated Balance Sheets when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statements of Income (Loss) by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statements of Income (Loss) in future periods when the amounts are reflected in customer rates. If an application is filed to modify customer rates with certain regulatory commissions, AltaGas is permitted to charge customers new rates, subject to refund, until the regulatory commission renders a final decision. During this interim period, a provision is recorded for a rate refund regulatory liability based on the difference between the amount collected in rates and the amount expected to be recovered from a final regulatory decision. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA. If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheets and included in the Consolidated Statements of Income (Loss) for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities. The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as at December 31, 2019 and 2018 , over which the Corporation expects to realize or settle the assets or liabilities: As at December 31 2019 2018 Recovery Period Regulatory assets - current Deferred cost of gas (a) $ 7.6 $ 20.4 Less than one year Accelerated replacement recovery mechanisms (b) 2.5 — Less than one year Interruptible sharing (a) 2.7 0.6 Less than one year $ 12.8 $ 21.0 Regulatory assets - non-current Deferred regulatory costs (a) (c) $ 149.5 $ 215.5 1 - 51 year s Future recovery of pension and other retirement benefits (a) 128.2 192.9 Various Future recovery of non-retirement employee benefits (a) (d) 19.4 21.3 Various Deferred pension costs (e) — 7.8 — Deferred environmental costs (a) (f) 17.7 19.9 Various Deferred loss on debt transactions and derivative instruments (a) (g) 99.2 109.3 Various Deferred future income taxes (a) (h) 42.7 67.0 Various Energy efficiency program - Maryland (i) 12.1 4.6 Various Other 17.9 24.7 Various $ 486.7 $ 663.0 Regulatory liabilities - current Deferred cost of gas (a) $ 60.2 $ 71.2 Less than one year Refundable tax credit (j) 1.9 3.8 Less than one year Federal income tax rate change (k) 33.1 26.2 Less than one year Virginia rate refund (l) 40.4 — Less than one year Accelerated replacement recovery mechanisms (b) 0.4 5.2 Less than one year Interruptible sharing (a) 0.4 2.3 Less than one year Other 9.1 6.2 Less than one year $ 145.5 $ 114.9 Regulatory liabilities - non-current Refundable tax credit (j) 3.9 6.1 2 years Future expense of pension and other retirement benefits (a) 261.2 166.7 Various Future removal and site restoration costs (m) 483.9 514.7 Various Deferred gain on debt transactions and derivative instruments (a) (g) 1.6 1.8 Various Federal income tax rate change (k) 628.3 698.4 Various Other 4.3 5.1 Various $ 1,383.2 $ 1,392.8 (a) Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions. (b) Represents amounts for deferred over or under collections of surcharges associated with Washington Gas' accelerated pipeline recovery programs in the District of Columbia, Maryland, and Virginia. (c) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled. (d) Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates. Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator. (e) In 2018, this balance related to previously deferred pension and other post-retirement benefits expenses that were fully amortized in 2019. (f) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates. (g) The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior fiscal years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. As at December 31, 2019 , this also includes a fair value adjustment of $79.8 million ( December 31, 2018 - $87.3 million ) recorded on the WGL Acquisition (Note 3 ). (h) This balance reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates. (i) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland. (j) On September 18, 2013, CINGSA received a US $15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA's customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology. (k) The Tax Cuts and Jobs Act (TCJA) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities in 2018 to the lower federal corporate tax rate of 21 percent , resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers. (l) Represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2019 Virginia rate case. (m) This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Income ($ millions) Available-for-sale Defined benefit pension and PRB plans Hedge net investments Translation foreign operations Equity investee Total Opening balance, January 1, 2019 $ — $ (19.0 ) $ (209.2 ) $ 801.4 $ 5.8 $ 579.0 OCI before reclassification — 15.2 68.2 (406.2 ) (0.7 ) (323.5 ) Amounts reclassified from OCI — 1.1 — — — 1.1 Current period OCI (pre-tax) — 16.3 68.2 (406.2 ) (0.7 ) (322.4 ) Income tax on amounts retained in AOCI — (3.2 ) (8.2 ) — — (11.4 ) Income tax on amounts reclassified to earnings — (0.3 ) — — — (0.3 ) Net current period OCI — 12.8 60.0 (406.2 ) (0.7 ) (334.1 ) Ending balance, December 31, 2019 $ — $ (6.2 ) $ (149.2 ) $ 395.2 $ 5.1 $ 244.9 Opening balance, January 1, 2018 $ (7.1 ) $ (11.4 ) $ (129.0 ) $ 342.9 $ 3.7 $ 199.1 OCI before reclassification — (14.1 ) (90.6 ) 458.5 2.1 355.9 Amounts reclassified from AOCI — 0.7 — — — 0.7 Adoption of ASU No. 2016-01 7.1 — — — — 7.1 Curtailment of DB and PRB plan — 4.2 — — — 4.2 Current period OCI (pre-tax) 7.1 (9.2 ) (90.6 ) 458.5 2.1 367.9 Income tax on amounts retained in AOCI — 3.3 10.4 — — 13.7 Income tax on amounts reclassified to earnings — (0.2 ) — — — (0.2 ) Income tax on amounts related to curtailment of DB and PRB plan — (1.5 ) — — — (1.5 ) Net current period OCI 7.1 (7.6 ) (80.2 ) 458.5 2.1 379.9 Ending balance, December 31, 2018 $ — $ (19.0 ) $ (209.2 ) $ 801.4 $ 5.8 $ 579.0 Reclassification From Accumulated Other Comprehensive Income AOCI components reclassified Income statement line item Year Ended December 31, 2019 Year Ended Defined benefit pension and PRB plans Other income $ 1.1 $ 0.7 Deferred income taxes Income tax expense – deferred (0.3 ) (0.2 ) $ 0.8 $ 0.5

Financial Instruments and Finan

Financial Instruments and Financial Risk Management	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Financial Instruments and Financial Risk Management	Financial Instruments and Financial Risk Management The Corporation’s financial instruments consist of cash and cash equivalents, accounts receivable, risk management contracts, certain long-term investments and other assets, accounts payable and accrued liabilities, dividends payable, short-term and long-term debt and certain other current and long-term liabilities. Fair Value Hierarchy AltaGas categorizes its financial assets and financial liabilities into one of three levels based on fair value measurements and inputs used to determine the fair value. Level 1 - fair values are based on unadjusted quoted prices in active markets for identical assets or liabilities. Fair values are based on direct observations of transactions involving the same assets or liabilities and no assumptions are used. Included in this category are publicly traded shares valued at the closing price as at the balance sheet date. Level 2 - fair values are determined based on valuation models and techniques where inputs other than quoted prices included within Level 1 are observable for the asset or liability either directly or indirectly. AltaGas enters into derivative instruments in the futures, over-the-counter and retail markets to manage fluctuations in commodity prices and foreign exchange rates. The fair values of power, natural gas and NGL derivative contracts were calculated using forward prices based on published sources for the relevant period, adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of foreign exchange option contracts was calculated using a variation of the Black-Scholes pricing model. Level 3 - fair values are based on inputs for the asset or liability that are not based on observable market data. AltaGas uses valuation techniques when observable market data is not available. A variety of valuation methodologies are used to determine the fair value of Level 3 derivative contracts, including developed valuation inputs and pricing models. The prices used in the valuations are corroborated using multiple pricing sources, and the Corporation periodically conducts assessments to determine whether each valuation model is appropriate for its intended purpose. Level 3 derivatives include physical contracts at illiquid market locations with no observable market data, long-dated positions where observable pricing is not available over the life of the contract, contracts valued using historical spot price volatility assumptions, and valuations using indicative broker quotes for inactive market locations. The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments: Other current liabilities - the carrying amounts approximate fair value because of the short maturity of these instruments. Current portion of long-term debt, Long-term debt and Other long-term liabilities - the fair value of these liabilities was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. Risk management assets and liabilities - the fair values of power, natural gas and NGL derivative contracts were calculated using forward prices from published sources for the relevant period. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of Level 3 derivative contracts was calculated using internally developed valuation inputs and pricing models. Equity securities – the fair value of equity securities was calculated using quoted market prices. Loans and receivables – the fair value of these assets was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. As at December 31, 2019 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income (a) Risk management assets - current $ 81.4 $ — $ 30.4 $ 51.0 $ 81.4 Risk management assets - non-current 30.9 — 6.7 24.2 30.9 Equity securities (b) 4.3 4.3 — — 4.3 Fair value through regulatory assets (a) Risk management assets - current 5.2 — — 5.2 5.2 Risk management assets - non-current 8.2 — 0.4 7.8 8.2 Amortized cost Loans and receivables (b) 45.0 — 46.1 — 46.1 $ 175.0 $ 4.3 $ 83.6 $ 88.2 $ 176.1 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 120.6 $ — $ 98.7 $ 21.9 $ 120.6 Risk management liabilities - non-current 77.0 — 19.2 57.8 77.0 Fair value through regulatory liabilities (a) Risk management liabilities - current 4.2 — 0.6 3.6 4.2 Risk management liabilities - non-current 90.0 — — 90.0 90.0 Amortized cost Current portion of long-term debt 922.9 — 922.9 — 922.9 Long-term debt 5,927.8 — 6,263.8 — 6,263.8 Other current liabilities (c) 15.4 — 15.4 — 15.4 $ 7,157.9 $ — $ 7,320.6 $ 173.3 $ 7,493.9 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (c) Excludes non-financial liabilities. As at December 31, 2018 Carrying Level 1 Level 2 Level 3 Total Financial assets Fair value through net income (a) Risk management assets - current $ 99.0 $ — $ 68.3 $ 30.7 $ 99.0 Risk management assets - non-current 49.0 — 18.0 31.0 49.0 Equity securities (b) 8.4 8.4 — — 8.4 Fair value through regulatory assets (a) Risk management assets - current 15.1 — 2.7 12.4 15.1 Risk management assets - non-current 8.7 — — 8.7 8.7 Amortized cost Loans and receivables (b) 45.0 — 45.2 — 45.2 $ 225.2 $ 8.4 $ 134.2 $ 82.8 $ 225.4 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 72.0 $ — $ 41.3 $ 30.7 $ 72.0 Risk management liabilities - non-current 103.4 — 15.3 88.1 103.4 Fair value through regulatory liabilities (a) Risk management liabilities - current 17.3 — 2.9 14.4 17.3 Risk management liabilities - non-current 109.6 — 0.1 109.5 109.6 Amortized cost Current portion of long-term debt 890.2 — 884.4 — 884.4 Long-term debt 8,066.9 — 8,040.3 — 8,040.3 Other current liabilities (c) 11.2 — 11.2 — 11.2 Other long-term liabilities (c) 2.0 — 2.0 — 2.0 $ 9,272.6 $ — $ 8,997.5 $ 242.7 $ 9,240.2 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (c) Excludes non‑financial liabilities. The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments as at December 31, 2019 : Net Fair Value Valuation Technique Unobservable Inputs Range Natural gas $ (83.8 ) Discounted Cash Flow Natural Gas Basis Price (per dekatherm) $ (1.18 ) - $ 3.27 Natural gas $ (1.4 ) Option Model Natural Gas Basis Price (per dekatherm) $ (1.19 ) - $ 3.30 Annualized Volatility of Spot Market Natural Gas 29 % - 906 % Electricity $ 0.1 Discounted Cash Flow Electricity Congestion Price (per megawatt hour) $ (6.73 ) - $ 65.26 The following tables provide a reconciliation of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy: For the year ended December 31 2019 2018 Natural Electricity Total Natural Electricity Total Balance, beginning of year $ (148.5 ) $ (14.7 ) $ (163.2 ) $ — $ — $ — Acquired (note 3) — — — (136.1 ) (10.6 ) (146.7 ) Realized and unrealized gains (losses): Recorded in income 47.6 1.4 49.0 (8.3 ) (6.5 ) (14.8 ) Recorded in regulatory assets 23.6 — 23.6 (5.9 ) — (5.9 ) Transfers into Level 3 (9.0 ) — (9.0 ) — — — Transfers out of Level 3 12.3 — 12.3 7.3 — 7.3 Purchases — (11.4 ) (11.4 ) — 6.4 6.4 Settlements (17.1 ) 24.4 7.3 0.3 (3.4 ) (3.1 ) Foreign exchange translation 5.9 0.4 6.3 (5.8 ) (0.6 ) (6.4 ) Balance, end of year $ (85.2 ) $ 0.1 $ (85.1 ) $ (148.5 ) $ (14.7 ) $ (163.2 ) Transfers between different levels of the fair value hierarchy may occur based on fluctuations in the valuation and on the level of observable inputs used to value the instruments from period to period. Transfers into and out of the different levels of the fair value hierarchy are presented at the fair value as of the beginning of the period. Transfers out of Level 3 during the year ended December 31, 2019 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the year ended December 31, 2019 were due to an increase in unobservable market inputs used in valuations. Realized and Unrealized Gains (Losses) Recorded to Income for Level 3 Measurements Year Ended December 31 2019 2018 Recorded to revenue $ 75.2 $ (11.1 ) Recorded to cost of sales (26.2 ) (3.7 ) $ 49.0 $ (14.8 ) Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income (Loss) Year Ended December 31 2019 2018 Natural gas $ 22.5 $ (2.2 ) Energy exports (86.7 ) — NGL frac spread (17.4 ) 40.0 Power (4.9 ) 9.3 Foreign exchange 1.2 33.7 $ (85.3 ) $ 80.8 Offsetting of Derivative Assets and Derivative Liabilities Certain of AltaGas’ risk management contracts are subject to master netting arrangements that create a legally enforceable right for a counterparty to offset the related financial assets and financial liabilities. As part of these master netting agreements, cash, letters of credit and parental guarantees may be required to be posted or obtained from counterparties in order to mitigate credit risk related to both derivative and non-derivative positions. Collateral balances are also offset against the related counterparties’ derivative positions to the extent the application would not result in the over-collateralization of those derivative positions on the balance sheet. As at December 31, 2019 Risk management assets (a) Gross amounts of recognized Gross amounts Netting Net amounts Natural gas $ 121.2 $ (53.7 ) $ — $ 67.5 Energy exports 9.7 (2.7 ) 4.4 11.4 NGL frac spread 0.3 (0.2 ) — 0.1 Power 53.5 (6.8 ) — 46.7 $ 184.7 $ (63.4 ) $ 4.4 $ 125.7 Risk management liabilities (b) Natural gas $ 226.1 $ (53.7 ) $ (27.7 ) $ 144.7 Energy exports 89.5 (2.7 ) — 86.8 NGL frac spread 1.7 (0.2 ) — 1.5 Power 68.7 (6.8 ) (3.1 ) 58.8 $ 386.0 $ (63.4 ) $ (30.8 ) $ 291.8 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $86.6 million and risk management assets (non‑current) balance of $39.1 million . (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $124.8 million and risk management liabilities (non‑current) balance of $167.0 million . As at December 31, 2018 Risk management assets (a) Gross amounts of Gross amounts Netting Net amounts Natural gas $ 200.8 $ (82.0 ) $ — $ 118.8 NGL frac spread 18.7 (0.7 ) — 18.0 Power 42.8 (7.8 ) — 35.0 $ 262.3 $ (90.5 ) $ — $ 171.8 Risk management liabilities (b) Natural gas $ 340.4 $ (82.0 ) $ (3.3 ) $ 255.1 NGL frac spread 2.7 (0.7 ) — 2.0 Power 50.6 (7.8 ) 1.2 44.0 Foreign exchange 1.2 — — 1.2 $ 394.9 $ (90.5 ) $ (2.1 ) $ 302.3 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $114.1 million and risk management assets (non‑current) balance of $57.7 million . (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $89.3 million and risk management liabilities (non‑current) balance of $213.0 million . Cash Collateral The following table presents collateral not offset against risk management assets and liabilities: As at December 31, December 31, Collateral posted with counterparties $ 29.1 $ 27.6 Cash collateral held representing an obligation $ 0.3 $ 0.8 Any collateral posted that is not offset against risk management assets and liabilities is included in line item “prepaid expenses and other current assets” in the Consolidated Balance Sheets. Collateral received and not offset against risk management assets and liabilities is included in line item “customer deposits” in the Consolidated Balance Sheets. Certain derivative instruments contain contract provisions that require collateral to be posted if the credit rating of AltaGas or certain of its subsidiaries falls below certain levels. At December 31, 2019 , AltaGas has posted $5.5 million ( December 31, 2018 - $ nil ) of collateral related to its derivative liabilities that contained credit-related contingent features. The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if specific credit-risk-related contingent features underlying these agreements were triggered: As at December 31, December 31, Risk management liabilities with credit-risk-contingent features $ 42.2 $ 14.7 Maximum potential collateral requirements $ 29.0 $ 7.5 Risks associated with financial instruments AltaGas is exposed to various financial risks in the normal course of operations such as market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates as well as credit risk and liquidity risk. Commodity Price Risk AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices. The use of derivative instruments is governed under formal risk management policies and is subject to parameters set out by AltaGas’ Risk Management Committee and Board of Directors. AltaGas does not make use of derivative instruments for speculative purposes. Natural Gas In the normal course of business, AltaGas purchases and sells natural gas to support its infrastructure business. The fixed price and market price contracts for both the purchase and sale of natural gas extend to 2033 . In addition, AltaGas may enter into financial derivative contracts as part of WGL’s asset optimization program. WGL optimized the value of its long-term natural gas transportation and storage capacity resources during periods when these resources are not being used to physically serve utility customers. AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2019 and 2018 : December 31, 2019 Fixed price (per GJ) Period Notional volume (GJ) Fair Value Sales 1.32 to 6.81 1-166 698,126,985 $ 28.9 Purchases 0.22 to 6.81 1-167 1,406,991,689 $ (104.4 ) Swaps 0.22 to 10.24 1-51 541,652,374 $ (1.7 ) December 31, 2018 Fixed price Period Notional volume (GJ) Fair Value Sales 1.07 to 12.19 1-178 858,640,810 $ 19.0 Purchases 0.69 to 16.26 1-179 1,638,207,391 $ (179.5 ) Swaps 2.56 to 15.37 1-231 621,578,572 $ 20.9 Energy Exports AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to the propane price differential between North American Indices and the Far East Index for contracts not under tolling arrangements at RIPET. AltaGas had the following contracts outstanding as at December 31, 2019 : December 31, 2019 Fixed price Period Notional volume (Bbl) Fair Value Propane 21.49 to 29.71 1-27 9,374,826 $ (75.4 ) NGL Frac Spread AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2019 and 2018 : December 31, 2019 Fixed price Period (months) Notional volume Fair Value Butane swaps 73.02 to 75.15/Bbl 1-12 346,852 Bbl $ (0.5 ) Crude oil swaps 73.02 to 75.15/Bbl 1-12 212,587 Bbl $ (0.9 ) Natural gas swaps 1.58 to 1.86/GJ 1-12 3,883,992 GJ $ — December 31, 2018 Fixed price Period Notional volume Fair Value Propane swaps $38.89 to $47.63/Bbl 1-12 1,725,114 Bbl $ 12.6 Butane swaps $52.95 to $55.26/Bbl 1-12 74,371 Bbl $ 1.2 Crude oil swaps $79.64 to $86.28/Bbl 1-12 329,230 Bbl $ 6.0 Natural gas swaps $1.38 to $1.68/GJ 1-12 9,490,365 GJ $ (3.8 ) Power AltaGas sells power to the Alberta Electric System Operator at market prices. AltaGas also sells power through its WGL Energy Services affiliate, to commercial, industrial and mass market users within the PJM Regional Transmission Organization at fixed and market prices. AltaGas' strategy is to mitigate the cash flow risk to Alberta power prices to provide predictable earnings. Therefore, AltaGas uses third-party swaps and purchase contracts to fix the prices over time on a portion of the volumes to mitigate financial exposure associated with the sale contracts. These power purchase and sale contracts extend to 2024 . As at December 31, 2019 , AltaGas had no intention to terminate any contracts prior to maturity. AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2019 and 2018 : December 31, 2019 Fixed price Period Notional volume (MWh) Fair Value Power sales 31.63 to 66.76 1-42 8,034,024 $ 39.0 Power purchases 31.63 to 66.76 1-60 8,552,467 $ (27.3 ) Swap purchases (7.88) to 74.26 1-48 25,058,577 $ (23.8 ) December 31, 2018 Fixed price Period Notional volume (MWh) Fair Value Power sales 26.90 to 95.03 1-60 11,881,575 $ (1.9 ) Power purchases 25.50 to 50.25 1-42 8,507,874 $ 16.4 Swap purchases (6.07) to 76.18 1-48 20,957,180 $ (22.3 ) The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2019 : Factor Increase or decrease to forward prices Increase or decrease to income before tax ($ millions) Alberta power price $1/MWh 2.3 PJM power price US$1/MWh 1.9 AECO natural gas price $0.50/GJ 1.1 NYMEX natural gas price US$0.50/GJ 2.6 Energy Exports: Propane Far East Index to Mont Belvieu spread $1/Bbl 3.4 Baltic LPG Freight $1/Bbl 6.1 NGL frac spread: Western Texas Intermediate (WTI) crude oil $1/Bbl 0.6 Natural gas $0.50/GJ 1.9 Foreign Exchange Risk AltaGas is exposed to foreign exchange risk as changes in foreign exchange rates may affect the fair value or future cash flows of the Corporation’s financial instruments. AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and OCI are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares outstanding. AltaGas may also enter into foreign exchange forward derivatives to manage the risk of fluctuating cash flows due to variations in foreign exchange rates. As at December 31, 2019 and December 31, 2018 , AltaGas did not have any outstanding foreign exchange forward contracts. AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2019 , AltaGas has designated US$300.0 million of outstanding debt as a net investment hedge ( December 31, 2018 - US$1,494.0 million ). For the year ended December 31, 2019 , AltaGas incurred after-tax unrealized gains of $60.0 million arising from the translation of debt in OCI ( 2018 ‑ after-tax unrealized loss of $80.2 million ). Interest Rate Risk AltaGas is exposed to interest rate risk as changes in interest rates may impact future cash flows and the fair value of its financial instruments. The Corporation manages its interest rate risk by holding a mix of both fixed and floating interest rate debt. As at December 31, 2019 , approximately 76 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates ( December 31, 2018 - 59 percent ). In addition, from time to time, AltaGas may enter into interest rate swap agreements to fix the interest rate on a portion of its banker’s acceptances issued under its credit facilities. There were no outstanding interest rate swaps as at December 31, 2019 . Credit Risk Credit risk results from the possibility that a counterparty to a financial instrument fails to fulfill its obligations in accordance with the terms of the contract. AltaGas' credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses that allow AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas maintains an allowance for doubtful accounts in the normal course of its business. AltaGas' maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. As at December 31, 2019 , AltaGas had no concentration of credit risk with a single counterparty. Weather Related Instruments WGL Energy Services utilizes heating degree day (HDD) instruments from time to time to manage weather and price risks related to its natural gas and electricity sales during the winter heating season. WGL Energy Services also utilizes cooling degree day (CDD) instruments and other instruments to manage weather and price risks related to its electricity sales during the summer cooling season. These instruments cover a portion of estimated revenue or energy-related cost exposure to variations in HDDs or CDDs. For the year ended December 31, 2019 , a pre-tax loss of $1.9 million was recorded related to these instruments (2018 - pre-tax loss of $1.0 million ). Accounts Receivable Past Due or Impaired AltaGas had the following past due or impaired accounts receivable (AR): As at December 31, 2019 Total AR accruals Receivables impaired Less than 30 days 31 to 60 days 61 to 90 days Over 90 days Trade receivable $ 1,238.2 $ 343.5 $ 33.2 $ 757.9 $ 61.2 $ 11.6 $ 30.8 Other 17.4 — — 17.3 — — 0.1 Allowance for credit losses (33.2 ) — (33.2 ) — — — — $ 1,222.4 $ 343.5 $ — $ 775.2 $ 61.2 $ 11.6 $ 30.9 As at December 31, 2018 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 1,574.6 $ 447.5 $ 54.7 $ 961.5 $ 74.1 $ 12.8 $ 24.0 Other 27.6 — — 27.5 — — 0.1 Allowance for credit losses (54.7 ) — (54.7 ) — — — — $ 1,547.5 $ 447.5 $ — $ 989.0 $ 74.1 $ 12.8 $ 24.1 Allowance for credit losses December 31, 2019 December 31, 2018 Balance, beginning of year $ 54.7 $ 2.4 Foreign exchange translation (2.6 ) 0.1 New allowance (a) 27.5 53.1 Change in allowance (b) (9.2 ) (0.9 ) Allowance applied to uncollectible customer accounts (37.2 ) — Balance, end of year $ 33.2 $ 54.7 (a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s allowance for credit losses of approximately $52.9 million . (b) Includes removal of allowance related to asset disposals of approximately $8.1 million in 2019. Liquidity Risk Liquidity risk is the risk that AltaGas will not be able to meet its financial obligations as they come due. AltaGas manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. AltaGas' objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required. AltaGas had the following contractual maturities with respect to financial liabilities: Contractual maturities by period As at December 31, 2019 Total Less than 1 year 1-3 years 4-5 years After 5 years Accounts payable and accrued liabilities $ 1,324.9 $ 1,324.9 $ — $ — $ — Dividends payable 22.3 22.3 — — — Short-term debt 460.0 460.0 — — — Other current liabilities (a) 15.4 15.4 — — — Risk management contract liabilities 291.8 124.8 34.1 13.2 119.7 Current portion of long-term debt (b) 920.4 920.4 — — — Long-term debt (b) 5,872.5 — 1,489.2 921.3 3,462.0 $ 8,907.3 $ 2,867.8 $ 1,523.3 $ 934.5 $ 3,581.7 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition. Contractual maturities by period As at December 31, 2018 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,488.2 $ 1,488.2 $ — $ — $ — Dividends payable 22.0 22.0 — — — Short-term debt 1,209.9 1,209.9 — — — Other current liabilities (a) 11.2 11.2 — — — Other long-term liabilities (a) 2.0 — 2.0 — — Risk management contract liabilities 302.3 89.3 113.3 33.3 66.4 Current portion of long-term debt (b) 888.5 888.5 — — — Long-term debt (b) 8,014.8 — 3,063.4 1,592.6 3,358.8 $ 11,938.9 $ 3,709.1 $ 3,178.7 $ 1,625.9 $ 3,425.2 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue	Revenue The following tables disaggregate revenue by major sources for the year: Year Ended December 31, 2019 Utilities Midstream Power Corporate Total Revenue from contracts with customers Commodity sales contracts $ — $ 1,093.7 $ 1,131.4 $ — $ 2,225.1 Midstream service contracts — 145.0 — — 145.0 Gas sales and transportation services 2,501.4 — — — 2,501.4 Storage services 28.1 — — — 28.1 Other 9.2 2.7 29.0 — 40.9 Total revenue from contracts with customers $ 2,538.7 $ 1,241.4 $ 1,160.4 $ — $ 4,940.5 Other sources of revenue Revenue from alternative revenue programs (a) $ 29.5 $ — $ — $ — $ 29.5 Leasing revenue (b) 0.9 136.6 105.1 — 242.6 Risk management and trading activities (c) (d) — 196.2 65.9 0.2 262.3 Other (4.9 ) 0.1 24.9 — 20.1 Total revenue from other sources $ 25.5 $ 332.9 $ 195.9 $ 0.2 $ 554.5 Total revenue $ 2,564.2 $ 1,574.3 $ 1,356.3 $ 0.2 $ 5,495.0 (a) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (b) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (c) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d). (d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2019 of $504.5 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018. Year Ended December 31, 2018 Utilities Midstream Power Corporate Total Revenue from contracts with customers Commodity sales contracts $ — $ 665.2 $ 497.5 $ — $ 1,162.7 Midstream service contracts — 205.0 — — 205.0 Gas sales and transportation services 1,684.3 — — — 1,684.3 Storage services 35.4 — — — 35.4 Other 10.7 0.6 25.1 — 36.4 Total revenue from contracts with customers $ 1,730.4 $ 870.8 $ 522.6 $ — $ 3,123.8 Other sources of revenue Revenue from alternative revenue programs (a) $ 21.7 $ — $ — $ — $ 21.7 Leasing revenue (b) 0.6 96.6 354.9 — 452.1 Risk management and trading activities (c) (d) 1.0 377.6 268.5 (2.9 ) 644.2 Other (1.1 ) (0.4 ) 16.0 0.4 14.9 Total revenue from other sources $ 22.2 $ 473.8 $ 639.4 $ (2.5 ) $ 1,132.9 Total revenue $ 1,752.6 $ 1,344.6 $ 1,162.0 $ (2.5 ) $ 4,256.7 (a) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (b) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (c) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. Revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d). (d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2018 of $264.2 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018. Revenue Recognition The following is a description of the Corporation’s revenue recognition policy by segment and by major source of revenue from contracts with customers. Utilities Segment Gas Sales and Transportation Services Customers are billed monthly based on regular meter readings. Customer billings are based on two main components: (i) a fixed service fee and (ii) a variable fee based on usage. Revenue is recognized over time when the gas has been delivered or as the service has been performed. As meter readings are performed on a cycle basis, AltaGas recognizes accrued revenue for any services rendered to its customers but not billed at month-end. The vast majority of these contracts are “at-will” as customers may cancel their service at any time, however, there are certain contracts that have terms of one year or longer. For these long-term contracts, there is generally a contract demand specified in the contract whereby the customer has to pay regardless of whether or not gas has been delivered. These contracts generally do not contain any make up rights and revenue is recognized on a monthly basis as service has been performed. Gas Storage Services Gas storage customers are billed monthly for services provided. Customer billings are based on four components: (i) reservation charges; (ii) capacity charges; (iii) injection/withdrawal charges; and (iv) excess charges. Reservation charges are based on the customer’s contract withdrawal quantity, capacity charges are based on the customer’s total contract quantity, and injection/withdrawal charges are based on the volume of gas delivered to or from the customer. Excess charges are applied to each day that the storage quantity exceeds 100 percent of the customer’s maximum storage quantity. Revenue is recognized as the service has been performed over time on a monthly basis, which corresponds to the invoice amount. The majority of these contracts have terms extending beyond one year. Midstream Segment Commodity Sales A portion of the NGL production from AltaGas’ extraction facilities is subject to frac spread between NGLs extracted and the natural gas purchased to make up the heating value of the NGLs extracted. For commodity sales contracts that do not meet the definition of a derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. These commodity sales contracts have varying terms but the majority of the contracts have a one -year term which coincides with the NGL year. AltaGas recognizes revenue for commodity sales contracts at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. Commodity sales contracts at the RIPET generate revenue from the sale and delivery of liquid propane purchased from upstream producers. Revenue from these sales contracts is recognized when propane is loaded onto transport vessels, which is the delivery point. AltaGas has the right to consideration in an amount that directly corresponds to the volumes of propane loaded on a vessel. Commodity sales also include gas sales to residential, commercial, and industrial customers in certain jurisdictions where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years . Customers are billed monthly based on the amount of gas delivered to the customer. Revenue is recognized based on the amount the Corporation is entitled to invoice the customer. Midstream Service Contracts AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, and transmission systems through a variety of contractual arrangements. For arrangements that do not contain a lease, the revenue is accounted for under ASC 606 as follows: Fee-for-service – The customer is charged a fee for the service provided on a per unit volume basis. Contract terms generally range from one month to up to the life of the reserves. Revenue under this type of arrangement is recognized over time as the service is provided, which corresponds to the customer’s monthly invoice amount. Take-or-pay – The customer has agreed to a minimum volume commitment whereby the customer must have AltaGas process or deliver a specified volume at a rate per unit that is specified in the contract. Quantities that the customer is unable to deliver are considered deficiency quantities. Certain of AltaGas’ take-or-pay contracts contain provisions whereby the customer can make up deficiency quantities in subsequent periods. Under this type of arrangement, any consideration received relating to the deficiency quantities that will be made up in a future period will be deferred until either: (i) the customer makes up the volumes or (ii) the likelihood that the customer will make up the volumes before the make up period expires becomes remote. If AltaGas does not expect the customer to make up the deficiency quantities (also referred to as breakage amount), AltaGas may recognize the expected breakage amount as revenue before the make up period expires. Significant judgment is required in estimating the breakage amount. For contracts where the customer has no make up rights, revenue is recognized on a monthly basis based on the higher of (i) the actual quantity delivered times the per unit rate or (ii) the contracted minimum amount. Power Segment For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. In instances where power generation is not sold under a power purchase agreement, the commodity is sold via a merchant market, or via commodity sales agreements which are accounted for as financial instruments. For commodity sales contracts that do not meet the definition of a lease, derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. Commodity Sales Energy generated from commercial solar and combined heating and power assets is sold under long-term power purchase agreements with a general duration of approximately 20 years . These long-term purchase agreements provide stable cash flow by way of contracted prices for the underlying commodities. During 2019, AltaGas closed the sale of its U.S. portfolio of distributed generation assets, which included wholly owned solar and fuel cell projects and tax equity partnership interests (Note 4 ). Subsequent to the sale, AltaGas will continue to generate energy from its combined heating and power assets. Commodity sales also include electricity sales to residential, commercial, and industrial customers in certain jurisdictions where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on meter readings or the amount of energy delivered to the customer. Revenue is recognized based on the amount the Corporation is entitled to invoice the customer. Contract Balances As at December 31, 2019 , a contract asset of $30.0 million has been recorded within long-term investments and other assets on the Consolidated Balance Sheets ( December 31, 2018 – $11.5 million ). This contract asset represents the difference in revenue recognized under a new rate in a blend-and-extend contract modification with a customer. Revenue from this contract modification will be recognized at the pre-modification rate for the remainder of the original term with the excess revenue recorded as a contract asset. The contract asset will be drawn down over the remaining term of the modified contract. In addition, at December 31, 2019 there is a contract asset of $58.6 million ( December 31, 2018 - $47.3 million ) recorded within prepaid expenses and other current assets on the Consolidated Balance Sheets for WGL Energy Systems’ unbilled revenue relating to design-build construction contracts. The contract asset represents unbilled amounts typically resulting from sales under contracts when the cost-to-cost method of revenue recognition is utilized, and revenue recognized exceeds the amount billed to the customer. Right to payment is achieved when the projects are formally “accepted” by the federal government. At December 31, 2019 , contract liabilities of $1.7 million ( December 31, 2018 - $2.2 million ) have been recorded within accounts payable and accrued liabilities on the Consolidated Balance Sheets. The contract liabilities consist of advance payments and billings in excess of revenue recognized and deferred revenue. Contract assets and liabilities are reported in a net position on a contract-by-contract basis at the end of each reporting period. Contract Assets As at December 31, December 31, Balance, beginning of year $ 58.8 $ — Additions 32.3 130.1 Transfers to held for sale (a) — (72.2 ) Transfers to accounts receivable (b) — (3.7 ) Foreign exchange translation (2.5 ) 4.6 Balance, end of year $ 88.6 $ 58.8 (a) In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset balance. Accordingly, the receivable was classified as held for sale at December 31, 2018. In February 2019, WGL Energy Systems completed the sale of the financing receivable (Note 4 ). (b) Amounts included in contract assets are transferred to accounts receivable when AltaGas’ right to consideration becomes unconditional. Contract Liabilities As at December 31, December 31, Balance, beginning of year $ 2.2 $ — Additions 1.9 2.6 Revenue recognized from contract liabilities (a) (2.2 ) (0.5 ) Foreign exchange translation (0.2 ) 0.1 Balance, end of year $ 1.7 $ 2.2 (a) Recognition of revenue related to performance obligations satisfied in the current period for amounts that were previously included in contract liabilities. Transaction price allocated to the remaining obligations The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of December 31, 2019 : 2020 2021 2022 2023 2024 2025 & beyond Total Midstream service contracts $ 113.1 $ 89.8 $ 88.9 $ 86.5 $ 86.4 $ 971.9 $ 1,436.6 Storage services 24.2 24.2 23.5 23.2 23.2 168.4 286.7 Other 19.4 8.9 2.0 2.0 2.0 12.0 46.3 $ 156.7 $ 122.9 $ 114.4 $ 111.7 $ 111.6 $ 1,152.3 $ 1,769.6 AltaGas applies the practical expedient available under ASC 606 and does not disclose information about the remaining performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which revenue is recognized at the amount to which AltaGas has the right to invoice for performance completed, and (iii) contracts with variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation. In addition, the table above does not include any estimated amounts of variable consideration that are constrained. The majority of midstream service contracts, gas sales and transportation service contracts, and storage service contracts contain variable consideration whereby uncertainty related to the associated variable consideration will be resolved (usually on a daily basis) as volumes are processed, gas is delivered or as service is provided.

Shareholders_ Equity

Shareholders’ Equity	12 Months Ended
	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Shareholders’ Equity	Shareholders’ Equity Authorization AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue such number of Preferred Shares in series at any time as have aggregate voting rights either directly or on conversion or exchange that in the aggregate represent less than 50 percent of the voting rights attaching to the then issued and outstanding Common Shares. Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan) The Plan consists of two components: a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended in December 2018. The Dividend Reinvestment and Optional Cash Purchase component was suspended in December 2019, with the December dividend (payable January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP. The Plan in its entirety will remain suspended until further notice. The Plan provided eligible holders of common shares with the opportunity to, at their election, reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) of the common shares on the applicable dividend payment date (the Dividend Reinvestment component of the Plan). In addition, the Plan provided shareholders who are enrolled in the Dividend Reinvestment component of the Plan with the opportunity to purchase new common shares at the average market price (with no discount) on the applicable dividend payment date (the Optional Cash Purchase component of the Plan). Each of the components of the Plan was subject to prorating and other limitations on availability of new common shares in certain events. The "average market price", in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of common shares on the Toronto Stock Exchange for the trading days on which at least one board lot of common shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Purchase component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that AltaGas is satisfied, in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements. Common Shares Issued and Outstanding Number of Amount January 1, 2018 175,279,216 $ 4,007.9 Shares issued on conversion of subscription receipts, net of issuance costs 84,510,000 2,305.6 Shares issued for cash on exercise of options 57,275 1.3 Deferred taxes on share issuance cost — 13.3 Shares issued under DRIP 15,377,575 325.8 December 31, 2018 275,224,066 $ 6,653.9 Shares issued for cash on exercise of options 76,177 1.2 Deferred taxes on share issuance cost — (3.9 ) Shares issued under DRIP 3,774,442 67.8 Issued and outstanding at December 31, 2019 279,074,685 $ 6,719.0 Preferred Shares As at December 31, 2019 December 31, 2018 Issued and Outstanding Number of shares Amount Number of shares Amount Series A 5,511,220 $ 137.8 5,511,220 $ 137.8 Series B 2,488,780 62.2 2,488,780 62.2 Series C 8,000,000 205.6 8,000,000 205.6 Series E 8,000,000 200.0 8,000,000 200.0 Series G 6,885,823 172.1 8,000,000 200.0 Series H 1,114,177 27.9 — — Series I 8,000,000 200.0 8,000,000 200.0 Series K 12,000,000 300.0 12,000,000 300.0 Washington Gas $4.80 series — — 150,000 19.7 $4.25 series — — 70,600 9.4 $5.00 series — — 60,000 7.9 Share issuance costs, net of taxes (28.5 ) (27.9 ) Fair value adjustment on WGL Acquisition (note 3) — 4.1 52,000,000 $ 1,277.1 52,280,600 $ 1,318.8 On December 20, 2019, all outstanding Washington Gas preferred shares (US $4.25 series, US $4.80 series, and US $5.00 series) were redeemed. A gain of $3.5 million was recognized upon redemption. . The following table outlines the characteristics of the cumulative redeemable preferred shares (a) : Current yield Annual dividend per share (b) Redemption price per share Redemption and conversion option date (c)(d) Right to convert into (d) Series A (e) 3.380 % $0.84500 $25 September 30, 2020 Series B Series B (f) (g) Floating Floating $25 September 30, 2020 Series A Series C (h) 5.290 % US$1.32250 US$25 September 30, 2022 Series D Series E (e) 5.393 % $1.34825 $25 December 31, 2023 Series F Series G (e) 4.620 % $1.15575 $25 September 30, 2024 Series H Series H (f) (g) Floating Floating $25 September 30, 2024 Series G Series I (i) 5.250 % $1.31250 $25 December 31, 2020 Series J Series K (j) 5.000 % $1.25000 $25 March 31, 2022 Series L (a) This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares, Series F Shares, and Series J Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, Series J Shares, and Series L Shares are also redeemable for $25.50 , and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption. (b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares, and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares and Series H Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series J Shares, and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. (c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. (d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter. (e) Holders of Series A Shares, Series E Shares, and Series G Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares). (f) Holders of Series B Shares and Series H Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent (Series B Shares) and 3.06 percent (Series H Shares). Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2019, the floating quarterly dividend rate is $0.26803 per share for Series B Shares and $0.29289 per share for Series H Shares for the period starting December 31, 2019 to, but excluding, March 31, 2020. (g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. Series H Shares can be redeemed for $25.50 per share on any date after September 30, 2019 that is not a Series H conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. (h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent . (i) Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent , provided that, in any event, such rate shall not be less than 5.25 percent per annum. (j) Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent , provided that, in any event, such rate shall not be less than 5.00 percent per annum. Share Option Plan AltaGas has an employee share option plan under which officers, employees, and service providers (as defined by the TSX) are eligible to receive grants. As at December 31, 2019 , 13,915,160 shares were reserved for issuance under the plan. As at December 31, 2019 , share options granted under the plan have a term between six and ten years until expiry and vest no longer than over a four ‑year period. As at December 31, 2019 , the unexpensed fair value of share option compensation cost associated with future periods was $4.5 million ( December 31, 2018 ‑ $3.7 million ). The following table summarizes information about the Corporation’s share options: December 31, 2019 December 31, 2018 As at Options outstanding Options outstanding Number of Exercise price (a) Number of Exercise price (a) Share options outstanding, beginning of year 6,309,183 $ 25.18 4,533,761 $ 32.35 Granted 2,287,385 19.12 2,811,460 16.69 Exercised (76,177 ) 14.52 (57,275 ) 20.68 Forfeited (1,165,435 ) 27.31 (878,013 ) 36.47 Expired (311,000 ) 36.16 (100,750 ) 14.60 Share options outstanding, end of year 7,043,956 $ 22.49 6,309,183 $ 25.18 Share options exercisable, end of year 2,921,642 $ 27.70 2,897,723 $ 32.01 (a) Weighted average. As at December 31, 2019 , the aggregate intrinsic value of the total share options exercisable was $3.3 million ( December 31, 2018 - $ nil ), the total intrinsic value of share options outstanding was $12.1 million ( December 31, 2018 - $ nil ) and the total intrinsic value of share options exercised was $0.4 million ( December 31, 2018 - $0.3 million ). The following table summarizes the employee share option plan as at December 31, 2019 : Options outstanding Options exercisable Number outstanding Weighted average exercise price Weighted average remaining contractual life Number exercisable Weighted average exercise price Weighted average remaining contractual life $14.52 to $18.00 2,557,328 $ 15.19 4.98 638,385 $ 14.62 4.79 $18.01 to $25.08 1,961,805 19.78 4.77 305,750 21.05 0.96 $25.09 to $46.70 2,524,823 32.00 2.72 1,977,507 32.95 2.39 7,043,956 $ 22.49 4.11 2,921,642 $ 27.70 2.77 The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows: Year ended December 31 2019 2018 Fair value per options ($) 2.30 1.27 Risk-free interest rate (%) 1.48 1.99 Expected life (years) 6 6 Expected volatility (%) 24.84 23.23 Annual dividend per share ($) (a) 0.96 1.18 Forfeiture rate (%) — — (a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as the grant dates. Phantom Unit Plan (Phantom Plan) and Deferred Share Unit Plan (DSUP) AltaGas has a Phantom Plan for employees and executive officers, which includes restricted units (RUs) and performance units (PUs) with vesting periods of 36 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of deferred share units (DSUs) to directors. DSUs granted under the DSUP vest immediately but settlement of the DSUs occur when the individual ceases to be a director. PUs, RUs, and DSUs (number of units) 2019 2018 Balance, beginning of year 9,908,154 564,549 Acquired (a) — 5,291,621 Converted to cash (a) — (5,291,621 ) Granted 674,971 9,502,347 Exercised (113,668 ) — Vested and paid out (677,667 ) (148,154 ) Forfeited (3,377,962 ) (66,522 ) Units in lieu of dividends 71,003 55,934 Outstanding, end of year 6,484,831 9,908,154 (a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit. At December 31, 2019, the WGL PUs comprised approximately 4.9 million of the outstanding units (December 31, 2018 - 8.9 million ). For the year ended December 31, 2019 , the compensation expense recorded for the Phantom Plan and DSUP was $21.7 million ( 2018 – $16.6 million ). As at December 31, 2019 , the unrecognized compensation expense relating to the remaining vesting period for the Phantom Plan was $21.8 million ( December 31, 2018 ‑ $26.9 million ) and is expected to be recognized over the vesting period.

Net Income (Loss) Per Common Sh

Net Income (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Net Income (Loss) Per Common Share	Net Income (Loss) Per Common Share The following table summarizes the computation of net income (loss) per common share: Year Ended December 31 2019 2018 Numerator: Net income (loss) applicable to controlling interests $ 833.5 $ (435.1 ) Less: Preferred share dividends (68.5 ) (66.6 ) Gain on redemption of preferred shares (note 25) 3.5 — Net income (loss) applicable to common shares $ 768.5 $ (501.7 ) Denominator: (millions) Weighted average number of common shares outstanding 276.9 222.6 Dilutive equity instruments (a) 0.5 — Weighted average number of common shares outstanding - diluted 277.4 222.6 Basic net income (loss) per common share $ 2.78 $ (2.25 ) Diluted net income (loss) per common share $ 2.77 $ (2.25 ) (a) Includes all options that have a strike price lower than the average share price of AltaGas' common shares during the periods noted. For the year ended December 31, 2019 , 4.3 million share options ( 2018 – 4.0 million ) were excluded from the diluted net income (loss) per share calculation as their effects were anti‑dilutive.

Other Income

Other Income	12 Months Ended
	Dec. 31, 2019
Other Income and Expenses [Abstract]
Other Income	Other Income Year Ended December 31 2019 2018 Gains (losses) from sale of assets $ 875.8 $ (10.6 ) Other components of net benefit cost (note 28) 27.4 18.9 Interest income and other revenue 9.0 2.7 Losses on investments (4.1 ) (10.1 ) $ 908.1 $ 0.9

Pension Plans and Retiree Benef

Pension Plans and Retiree Benefits	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Pension Plans and Retiree Benefits	Pension Plans and Retiree Benefits The costs of the defined benefit and post-retirement benefit plans are based on Management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits. Defined Contribution Plan AltaGas has a defined contribution (DC) pension plan for substantially all employees. The pension cost recorded for the DC plan was $19.8 million for the year ended December 31, 2019 ( 2018 - $15.4 million ). Defined Benefit Plans AltaGas has several defined benefit pension plans for unionized and non-unionized employees, including one in Canada (which is comprised of five divisions) and six in the United States. The plans in the United States include a qualified, trusteed, non-contributory defined benefit pension plan, and a non-funded defined benefit restoration plan maintained by Washington Gas. The defined benefit plans are partially funded except for two of the divisions in Canada which are fully funded and one of the plans in the United States which is not funded. AltaGas’ most recent actuarial valuation of the Canadian defined benefit plans for funding purposes was completed in 2016. AltaGas is required to file an actuarial valuation of its Canadian defined benefit plans with the pension regulators at least every three years. The next actuarial valuation for funding purposes is required to be completed as of a date no later than December 31, 2019, and will be filed with the pension regulators in 2020. Actuarial valuations for funding purposes are required annually for AltaGas’ U.S. defined benefit plans. Supplemental Executive Retirement Plans (SERP) AltaGas has non-registered, defined benefit plans that provide defined benefit pension benefits to eligible executives based on average earnings, years of service and age at retirement. The SERP benefits will be paid from the general revenue of the Corporation as payments come due or from the Rabbi Trusts funded as part of the WGL acquisition. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account. Several executive officers of Washington Gas participate in a separate non-funded defined benefit SERP (a non-qualified pension plan). This defined benefit SERP was closed to new entrants beginning January 1, 2010. Post-Retirement Benefit Plans AltaGas has several post-retirement benefit plans for unionized and non-unionized employees, including one in Canada and four in the United States. The post-retirement benefit plan in Canada is limited to the payment of life insurance and an annual allocation to a Healthcare Spending Account (HSA). This benefit plan is not funded. Post-retirement benefit plans in the United States provide certain medical, prescription drug, dental, and life insurance benefits to eligible retired employees, their spouses and covered dependents. Benefits are based on a combination of the retiree's age and years of service at retirement. For eligible Washington Gas retirees and dependents not yet receiving Medicare benefits, Washington Gas provides medical, prescription drug, and dental benefits through Preferred Provider Organization (PPO) or Health Maintenance Organization (HMO) plans, through the Washington Gas Light Company Retiree Medical Plan. For Medicare-eligible retirees age 65 and older and their dependents, eligible retirees and dependents participate in a tax-free Health Reimbursement Account (HRA) Plan. The HRA plan provides an annual subsidy to help purchase supplemental medical, prescription drug and dental coverage in the marketplace. One of these benefit plans is partially funded and three of them are fully funded. Rabbi Trusts Rabbi trusts of $57.4 million as at December 31, 2019 have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans ( December 31, 2018 - $89.3 million ). These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets. The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States: Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Projected benefit obligation (a) Balance, beginning of year $ 34.3 $ 1.9 $ 1,635.3 $ 458.0 $ 1,669.6 $ 459.9 Actuarial loss (gain) 2.1 0.2 182.0 (14.8 ) 184.1 (14.6 ) Current service cost 2.6 — 23.8 8.5 26.4 8.5 Member contributions — — — 2.2 — 2.2 Interest cost 1.2 0.1 67.8 19.1 69.0 19.2 Benefits paid (4.0 ) (0.1 ) (77.3 ) (24.4 ) (81.3 ) (24.5 ) Expenses paid (0.1 ) — (0.6 ) (0.1 ) (0.7 ) (0.1 ) Settlements — — (24.7 ) — (24.7 ) — Plan amendments — — 0.3 — 0.3 — Other — — — 1.0 — 1.0 Foreign exchange translation — — (82.0 ) (21.8 ) (82.0 ) (21.8 ) Balance, end of year $ 36.1 $ 2.1 $ 1,724.6 $ 427.7 $ 1,760.7 $ 429.8 Plan assets Fair value, beginning of year $ 13.8 $ — $ 1,354.1 $ 791.2 $ 1,367.9 $ 791.2 Actual return on plan assets 0.9 — 284.2 177.4 285.1 177.4 Employer contributions 4.3 0.1 38.7 0.1 43.0 0.2 Member contributions — — — 2.2 — 2.2 Benefits paid (4.0 ) (0.1 ) (77.3 ) (23.7 ) (81.3 ) (23.8 ) Expenses paid (0.1 ) — (0.6 ) (0.1 ) (0.7 ) (0.1 ) Settlements — — (25.7 ) — (25.7 ) — Other — — — 0.1 — 0.1 Foreign exchange translation — — (69.5 ) (41.3 ) (69.5 ) (41.3 ) Fair value, end of year $ 14.9 $ — $ 1,503.9 $ 905.9 $ 1,518.8 $ 905.9 Funded status $ (21.2 ) $ (2.1 ) $ (220.7 ) $ 478.2 $ (241.9 ) $ 476.1 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. Year Ended December 31, 2018 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Projected benefit obligation (a) Balance, beginning of year $ 165.6 $ 15.8 $ 303.8 $ 82.7 $ 469.4 $ 98.5 Plans disposed (132.1 ) (13.6 ) — — (132.1 ) (13.6 ) Actuarial gain (0.8 ) (0.1 ) (67.7 ) (33.8 ) (68.5 ) (33.9 ) Current service cost 2.4 0.1 16.2 5.3 18.6 5.4 Member contributions — — — 2.1 — 2.1 Interest cost 1.2 0.1 38.0 10.9 39.2 11.0 Benefits paid (2.7 ) — (43.2 ) (13.4 ) (45.9 ) (13.4 ) Expenses paid — — (0.9 ) (0.1 ) (0.9 ) (0.1 ) Plan combinations 0.7 — 1,311.7 382.9 1,312.4 382.9 Plan amendments — (0.4 ) — — — (0.4 ) Foreign exchange translation — — 77.4 21.4 77.4 21.4 Balance, end of year $ 34.3 $ 1.9 $ 1,635.3 $ 458.0 $ 1,669.6 $ 459.9 Plan assets Fair value, beginning of year $ 115.2 $ 8.1 $ 248.7 $ 70.8 $ 363.9 $ 78.9 Plans disposed (102.1 ) (8.1 ) — — (102.1 ) (8.1 ) Actual return on plan assets (0.3 ) — (54.7 ) (37.2 ) (55.0 ) (37.2 ) Employer contributions 3.4 — 7.6 2.5 11.0 2.5 Member contributions — — — 2.1 — 2.1 Benefits paid (2.7 ) — (43.2 ) (13.4 ) (45.9 ) (13.4 ) Expenses paid — — (0.9 ) (0.1 ) (0.9 ) (0.1 ) Plan combinations 0.3 — 1,133.2 732.7 1,133.5 732.7 Foreign exchange translation — — 63.4 33.8 63.4 33.8 Fair value, end of year $ 13.8 $ — $ 1,354.1 $ 791.2 $ 1,367.9 $ 791.2 Funded status $ (20.5 ) $ (1.9 ) $ (281.2 ) $ 333.2 $ (301.7 ) $ 331.3 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. The following amounts were included in the Consolidated Balance Sheets: December 31, 2019 December 31, 2018 Defined Benefit Post- Retirement Benefits Total Defined Benefit Post- Retirement Benefits Total (a) Prepaid post-retirement benefits $ — $ 486.8 $ 486.8 $ — $ 341.4 $ 341.4 Accounts payable and accrued liabilities (25.7 ) — (25.7 ) (27.6 ) — (27.6 ) Future employee obligations (216.2 ) (10.7 ) (226.9 ) (274.1 ) (10.1 ) (284.2 ) $ (241.9 ) $ 476.1 $ 234.2 $ (301.7 ) $ 331.3 $ 29.6 (a) Account balances on the Consolidated Balance Sheets also include certain non-pension related amounts. The accumulated benefit obligation for all defined benefit plans were: As at December 31, 2019 December 31, 2018 Canada United States Canada United States Accumulated benefit obligation (a) $ 34.7 $ 1,616.4 $ 32.9 $ 1,525.6 (a) Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels. The following amounts were recorded in other comprehensive income (loss) and have not yet been recognized in net periodic benefit cost: Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit (cost) $ (0.2 ) $ 0.3 $ 0.1 $ — $ (0.1 ) $ 0.3 Net actuarial gain (loss) (9.4 ) (0.7 ) (14.9 ) 18.2 (24.3 ) 17.5 Recognized in AOCI pre-tax $ (9.6 ) $ (0.4 ) $ (14.8 ) $ 18.2 $ (24.4 ) $ 17.8 Increase (decrease) by the amount 2.3 0.1 7.0 (9.0 ) 9.3 (8.9 ) Net amount in AOCI after-tax $ (7.3 ) $ (0.3 ) $ (7.8 ) $ 9.2 $ (15.1 ) $ 8.9 Year Ended December 31, 2018 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit (cost) $ (0.3 ) $ 0.4 $ (0.2 ) $ — $ (0.5 ) $ 0.4 Net actuarial loss (8.7 ) (0.5 ) (10.7 ) (5.0 ) (19.4 ) (5.5 ) Recognized in AOCI pre-tax $ (9.0 ) $ (0.1 ) $ (10.9 ) $ (5.0 ) $ (19.9 ) $ (5.1 ) Increase by the amount 2.4 — 2.2 1.4 4.6 1.4 Net amount in AOCI after-tax $ (6.6 ) $ (0.1 ) $ (8.7 ) $ (3.6 ) $ (15.3 ) $ (3.7 ) The following amounts were recorded in a regulatory asset (liability) and have not yet been recognized in net periodic benefit cost: Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service cost (credit) $ — $ — $ 1.1 $ (105.4 ) $ 1.1 $ (105.4 ) Net actuarial loss (gain) — — 127.1 (155.8 ) 127.1 (155.8 ) Recognized in regulatory asset (liability) $ — $ — $ 128.2 $ (261.2 ) $ 128.2 $ (261.2 ) Year Ended December 31, 2018 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service cost (credit) $ — $ — $ 0.8 $ (110.2 ) $ 0.8 $ (110.2 ) Net actuarial loss (gain) — — 188.2 (52.6 ) 188.2 (52.6 ) Recognized in regulatory asset (liability) $ — $ — $ 189.0 $ (162.8 ) $ 189.0 $ (162.8 ) The costs of the defined benefit and post-retirement benefit plans are based on Management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits. Amounts to be amortized in the next fiscal year from AOCI Defined Benefit Post-Retirement Benefits Past service cost (credit) $ 0.2 $ (0.7 ) Actuarial loss 4.0 0.3 Total $ 4.2 $ (0.4 ) Amounts to be amortized in the next fiscal year from regulatory assets (liabilities) Defined Benefit Post-Retirement Benefits Past service credit (cost) $ (0.2 ) $ 16.7 Actuarial gain (loss) (17.1 ) 0.5 Total $ (17.3 ) $ 17.2 The net pension expense by plan was as follows: Year Ended December 31, 2019 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 2.6 $ — $ 23.8 $ 8.5 $ 26.4 $ 8.5 Interest cost (b) 1.2 0.1 67.8 19.1 69.0 19.2 Expected return on plan assets (b) (0.5 ) — (74.6 ) (37.1 ) (75.1 ) (37.1 ) Amortization of past service cost (credit) (b) 0.1 — 0.4 (21.9 ) 0.5 (21.9 ) Amortization of net actuarial loss (b) 0.9 — 11.7 0.1 12.6 0.1 Plan settlements (b) — — 4.1 — 4.1 — Other (b) — — — 0.9 — 0.9 Net benefit cost (income) recognized $ 4.3 $ 0.1 $ 33.2 $ (30.4 ) $ 37.5 $ (30.3 ) (a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss) . (b) Recorded under the line item “ other income ” on the Consolidated Statements of Income (Loss) . Year Ended December 31, 2018 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 2.4 $ 0.1 $ 16.2 $ 5.3 $ 18.6 $ 5.4 Interest cost (b) 1.2 0.1 38.0 10.9 39.2 11.0 Expected return on plan assets (b) (0.5 ) — (49.9 ) (21.6 ) (50.4 ) (21.6 ) Amortization of past service cost (credit) (b) 0.1 — 0.1 (11.5 ) 0.2 (11.5 ) Amortization of net actuarial loss (b) 0.6 — 7.7 0.4 8.3 0.4 Net benefit cost (income) recognized $ 3.8 $ 0.2 $ 12.1 $ (16.5 ) $ 15.9 $ (16.3 ) (a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss) . (b) Recorded under the line item “ other income ” on the Consolidated Statements of Income (Loss) . The objective for fund returns, over three to five -year periods, is the sum of two components - a passive component, which is the benchmark index market returns for the asset mix in effect, plus the added value expected from active management. It is the Corporation’s belief that the potential additional returns justify the additional risk associated with active management. The risk inherent in the investment strategy over a market cycle (a three -to five -year period) is two-fold. There is a risk that the market returns, as measured by the benchmark returns, will not be in line with expectations. The other risk is that the expected added value of active management over passive management will not be realized over the time period prescribed in each fund manager's mandate. There is also the risk of annual volatility in returns, which means that in any one year the actual return may be very different from the expected return. Cash and money market investments may be held from time to time as short-term investment decisions at the discretion of the fund manager(s) within the constraints prescribed by their mandate(s). The Corporation's target asset mix for the Canadian plans is 45 percent to 55 percent fixed income assets. The target asset mix for SEMCO plans is 33 percent fixed income assets and for WGL plans is 50 percent to 60 percent fixed income assets. These objectives have taken into account the nature of the liabilities and the risk-reward tolerance of the Corporation. The collective investment mixes for the plans are as follows as at December 31, 2019 : Canada Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 1.9 $ 1.9 $ — 12.8 Canadian equities 4.1 4.1 — 27.5 Foreign equities 2.4 2.4 — 16.0 Fixed income 5.7 5.7 — 38.3 Real estate 0.8 — 0.8 5.4 $ 14.9 $ 14.1 $ 0.8 100.0 United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 10.8 $ 10.8 $ — 0.4 Canadian equities 2.6 2.6 — 0.1 Foreign equities (a) 302.5 302.2 0.3 12.6 Fixed income 933.0 123.2 809.8 38.7 Derivatives (0.2 ) — (0.2 ) — Other (b) 12.0 — 12.0 0.5 Total investments in the fair value hierarchy $ 1,260.7 $ 438.8 $ 821.9 52.3 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 648.9 26.9 Private equity/limited partnership (e) 55.6 2.3 Pooled separate accounts (f) 32.0 1.3 Collective trust fund (g) 433.8 18.1 Total fair value of plan investments $ 2,431.0 100.9 Net payable (h) (21.2 ) (0.9 ) $ 2,409.8 100.0 (a) Investments in foreign equities include U.S. and international securities. (b) As at December 31, 2019 , these investments consisted primarily of non-U.S. government bonds. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As at December 31, 2019 , investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans. (e) As at December 31, 2019 , investments in a private equity/limited partnership consisted of common stock of international companies. (f) As at December 31, 2019 , investments in pooled separate accounts consisted of income producing properties located in the United States. (g) As at December 31, 2019 , investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments. (h) As at December 31, 2019 , this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Total Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 12.7 $ 12.7 $ — 0.5 Canadian equities 6.7 6.7 — 0.3 Foreign equities (a) 304.9 304.6 0.3 12.6 Fixed income 938.7 128.9 809.8 38.7 Derivatives (0.2 ) — (0.2 ) — Real estate 0.8 — 0.8 — Other (b) 12.0 — 12.0 0.5 Total investments in the fair value hierarchy $ 1,275.6 $ 452.9 $ 822.7 52.6 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 648.9 26.8 Private equity/limited partnership (e) 55.6 2.3 Pooled separate accounts (f) 32.0 1.3 Collective trust fund (g) 433.8 17.9 Total fair value of plan investments $ 2,445.9 100.9 Net payable (h) (21.2 ) (0.9 ) $ 2,424.7 100.0 (a) Investments in foreign equities include U.S. and international securities. (b) As at December 31, 2019 , these investments consisted primarily of non-U.S. government bonds. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As at December 31, 2019 , investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans. (e) As at December 31, 2019 , investments in a private equity/limited partnership consisted of common stock of international companies. (f) As at December 31, 2019 , investments in pooled separate accounts consisted of income producing properties located in the United States. (g) As at December 31, 2019 , investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments. (h) As at December 31, 2019 , this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Year Ended December 31 2019 2018 Significant actuarial assumptions used in measuring net benefit plan costs Defined Post-Retirement Defined Post-Retirement Discount rate (%) 2.90 - 4.40 3.90 - 4.50 3.25 - 4.30 3.60 - 4.30 Expected long-term rate of return on plan assets (%) (a) 5.75 - 7.15 4.66 - 7.15 3.20 - 7.60 3.75 - 7.60 Rate of compensation increase (%) 2.75 - 4.10 4.10 2.75 - 4.10 4.10 Average remaining service life of active employees (years) 9.0 13.2 9.6 14.1 (a) Only applicable for funded plans As at December 31 2019 2018 Significant actuarial assumptions used in measuring benefit obligations Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 2.90 - 3.50 3.10 - 3.60 3.60 - 4.40 3.90 - 4.50 Rate of compensation increase (%) 2.75 - 4.00 3.50 2.75 - 4.10 4.10 The expected rate of return on assets is based on the current level of expected returns on risk free investments, the historical level of risk premium associated with other asset classes in which the portfolio is invested, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected rate of return on assets assumption for the portfolio. The discount rate is based on yields available on high-quality long-term corporate bonds, with maturities matching the estimated timing and amount of expected benefit payments. The estimates for health care benefits take into consideration increased health care benefits due to aging and cost increases in the future. The assumed health care cost trend rate used to measure the expected cost of benefits for the next year was 6.3 percent . The health care cost trend rates were assumed to decline to between 2.0 and 4.5 percent by 2027 . The assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percentage point change in the assumed health care trend rates would have the following effects for 2019 : Increase Decrease Service and interest costs $ 1.9 $ (1.5 ) Accrued benefit obligation $ 22.7 $ (18.4 ) The following table shows the expected cash flows for defined benefit pension and other post-retirement plans: Defined Benefit Post-Retirement Benefits Expected employer contributions: 2020 $ 37.0 $ 3.2 Expected benefit payments: 2020 $ 104.6 $ 23.8 2021 $ 85.1 $ 22.6 2022 $ 93.3 $ 22.5 2023 $ 90.0 $ 22.3 2024 $ 90.7 $ 22.1 2025 - 2028 $ 474.1 $ 112.6

Commitments, Guarantees, and Co

Commitments, Guarantees, and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments, Guarantees, and Contingencies	Commitments, Guarantees, and Contingencies Commitments AltaGas has long-term natural gas purchase and transportation arrangements, propane purchase agreements, electricity purchase arrangements, service agreements, pipeline and storage contracts, capital commitments, environmental commitments, merger commitments, and operating leases for office space, office equipment, rail cars, and automobile equipment, all of which are transacted at market prices and in the normal course of business. Future payments of these commitments as at December 31, 2019 are estimated as follows: 2020 2021 2022 2023 2024 2025 & beyond Total Gas purchase (a) $ 2,374.0 $ 2,488.2 $ 2,323.6 $ 2,076.1 $ 1,959.5 $ 22,772.0 $ 33,993.4 Propane purchase (b) 220.2 127.2 94.9 86.5 58.4 127.1 714.3 Electricity purchase (c) 567.2 318.1 160.0 56.4 11.0 0.4 1,113.1 Service agreements (d) (e) (f) 58.7 44.0 28.2 23.4 22.9 309.1 486.3 Pipeline and storage services (g) 721.2 652.5 627.8 600.4 550.5 3,876.7 7,029.1 Capital projects (h) 6.9 — — — — — 6.9 Operating leases (i) 27.8 27.1 26.5 24.5 20.1 100.1 226.1 Environmental (j) 6.5 4.3 1.0 1.0 0.6 0.4 13.8 Merger commitments (k) 8.2 3.8 1.9 1.9 1.9 4.3 22.0 $ 3,990.7 $ 3,665.2 $ 3,263.9 $ 2,870.2 $ 2,624.9 $ 27,190.1 $ 43,605.0 (a) AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period. (b) AltaGas enters into contracts to purchase propane for its operations at RIPET. These contracts are used to ensure that there is an adequate supply of propane to meet shipment commitments and to minimize exposure to market price fluctuations. Propane purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period. (c) AltaGas enters into contracts to purchase electricity from various suppliers for its non-utility business. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include US $17.4 million of commitments related to renewable energy credits. (d) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hours per CT, or 25 years , whichever comes first. The LTSA has variable fees on a per equivalent operating hour basis. As at December 31, 2019 , the total commitment was $167.9 million payable over the next 16 years , of which $45.4 million is expected to be paid over the next five years. (e) In 2017, AltaGas entered into a 12 -year service agreement for tug services to support the marine operations of RIPET. (f) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI), provision of certain terminal services, and access to RTI's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and RTI executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement. (g) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044. (h) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs. (i) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, and office and other equipment. (j) Environmental commitments include committed payments related to certain environmental response costs. (k) Represents the estimated future payments of merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that will be expensed when costs are incurred in the future, including the investment of up to US$70 million over a ten year period to further extend natural gas service, investment of US$8 million for leak mitigation within three years of the merger, hiring damage prevention trainers in each jurisdiction for a total of US$2 million over five years, and developing 15 megawatts of either electric grid energy storage or Tier 1 renewable resources within five years. As at December 31, 2019, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$17 million . Guarantees AltaGas has guaranteed payments primarily for certain commitments on behalf of some of its subsidiaries. AltaGas has also guaranteed payments for certain of its external partners. As at December 31, 2019 , AltaGas has no guarantees to external parties. Contingencies AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. While the final outcome of such legal claims and actions cannot be predicted with certainty, the Corporation does not believe that the resolution of such claims and actions will have a material impact on the Corporation’s consolidated financial position or results of operations. Antero Contract In June 2019, a jury trial was held in the County Court for Denver, Colorado to consider a contractual dispute relating to gas pricing between Washington Gas and WGL Midstream (together, the Companies) and Antero Resources Corporation (Antero) . Following the trial, the jury returned a verdict in favor of Antero for approximately US $96 million , of which approximately US $11 million was against Washington Gas with the remainder against WGL Midstream. Following the official entry of the judgment, the Companies filed an appeal on August 16, 2019. AltaGas recorded a net reduction to the acquired working capital of WGL of approximately US $45 million to account for the verdict in favor of Antero net of tax and other expected recoveries. Expected recoveries include a $33.1 million receivable recorded in "Long-term investments and other assets" on the Consolidated Balance Sheets for amounts expected to be recovered under a commercial arrangement with a third party. Silver Spring, Maryland Incident On April 23, 2019, the National Transportation and Safety Board (NTSB) held a hearing during which it found, among other things, that the probable cause of the August 10, 2016, explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland “was the failure of an indoor mercury service regulator with an unconnected vent line that allowed natural gas into the meter room where it accumulated and ignited from an unknown ignition source. Contributing to the accident was the location of the mercury service regulators where leak detection by odor was not readily available.” Washington Gas disagrees with the NTSB’s probable cause findings. Following this hearing, on June 10, 2019, the NTSB issued an accident report. A total of 37 civil actions related to the incident were filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits sought unspecified damages for personal injury and/or property damage. All personal injury and property damage claims asserted by residents at the Flower Branch Apartments have been settled and paid. Washington Gas has been reimbursed by its insurers for the amounts paid in the settlements. In connection with the incident, on September 5, 2019, the PSC of MD ordered Washington Gas, within 30 days, to (i) provide a detailed response to the NTSB’s probable cause findings and (ii) provide evidence regarding the status of a 2003 mercury regulator replacement program and, if the program was not completed, to show cause why the PSC of MD should not impose a civil penalty on Washington Gas. On November 18, 2019, the Technical Staff of the PSC of MD, the MD Office of People’s Counsel (OPC), Montgomery County, MD and the Apartment and Office Building Association of Metropolitan Washington (AOBA) filed written comments on Washington Gas' response to the Show-Cause Order. Technical Staff commented that the PSC of MD may impose a civil penalty but did not expressly recommend same. Montgomery County, MD, OPC and AOBA requested that the PSC of MD impose a civil penalty on Washington Gas. On December 17, 2019, the PSC of MD held a public hearing near the apartment complex at Arliss Street, at which some residents requested that Washington Gas accelerate and complete its mercury service regulator program and that Washington Gas absorb the cost of same. Washington Gas intends to file comments with the PSC of MD responding to all written comments and resident testimony. Management believes that the likelihood of a civil penalty is probable and has accrued US$0.3 million to reflect the minimum liability expected to result from the proceeding. Though Washington Gas is unable to estimate the maximum possible penalty, other parties recommended penalties ranging from US$32 million (AOBA, which argued that Washington Gas should absorb all costs of removal and relocation of mercury service regulators) to US$123.3 million (OPC, which argued that Washington Gas should absorb all costs of removal and relocation of mercury service regulators and pay a fine of US $25,000 per day for each day mercury service regulators remain on Washington Gas’ system).

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows: As at December 31, 2019 December 31, 2018 Due from related parties Accounts receivable (a) $ 17.8 $ 60.8 Long-term investments and other assets (b) 45.0 45.0 $ 62.8 $ 105.8 Due to related parties Accounts payable (c) $ 2.7 $ 6.3 Risk management liabilities - current (d) — 0.9 $ 2.7 $ 7.2 (a) Receivables from joint ventures and ACI. (b) AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021. As at December 31, 2019 , Petrogas had drawn $45.0 million ( December 31, 2018 - $45.0 million ) under the facility. (c) Payables to joint venture. (d) Foreign exchange hedge with ACI. The following transactions with related parties have been recorded on the Consolidated Statements of Income (Loss) for the years ended December 31, 2019 and 2018 : Year Ended December 31 2019 2018 Revenue (a) $ 114.9 $ 68.4 Cost of sales (b) $ 12.8 $ 4.2 Operating and administrative recoveries (c) $ (1.8 ) $ (1.3 ) Other income (d) $ 3.2 $ 9.2 (a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI. For the year ended December 31, 2018, revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million . (b) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates. (c) Administrative costs recovered from joint ventures. In addition, subsequent to the initial public offering (IPO) of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. (d) Interest income from loans to Petrogas (secured loan facility) and loans to ACI. Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of 2018. Loans to ACI were fully repaid by December 31, 2018.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information The following table details the changes in operating assets and liabilities from operating activities: Year Ended 2019 2018 Source (use) of cash: Accounts receivable $ 168.4 $ (526.9 ) Inventory (2.1 ) (100.8 ) Other current assets (85.5 ) 12.5 Regulatory assets - current 7.1 (15.8 ) Accounts payable and accrued liabilities (280.2 ) 237.9 Customer deposits (16.9 ) (13.3 ) Regulatory liabilities - current 34.2 69.2 Risk management liabilities - current 1.1 — Other current liabilities (5.6 ) (5.9 ) Other operating assets and liabilities (52.0 ) (143.4 ) Changes in operating assets and liabilities $ (231.5 ) $ (486.5 ) The following cash payments have been included in the determination of earnings: Year Ended 2019 2018 Interest paid (net of capitalized interest) $ 351.7 $ 288.9 Income taxes paid $ 67.2 $ 36.9 The following table is a reconciliation of cash and restricted cash balances: As at December 31 2019 2018 Cash and cash equivalents $ 57.1 $ 101.6 Restricted cash holdings from customers - current 4.0 4.1 Restricted cash holdings from customers - non-current 3.9 6.1 Restricted cash included in prepaid expenses and other current assets (a) 25.4 27.6 Restricted cash included in long-term investments and other assets (a) 32.0 61.7 Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows $ 122.4 $ 201.1 (a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relate to Rabbi trusts associated with WGL’s pension plans (see Note 28 ).

Segmented Information

Segmented Information	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Segmented Information	Segmented Information AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end‑user. The following describes the Corporation’s four reporting segments: Utilities n rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia; n rate-regulated natural gas storage in the United States; and n equity investment in AltaGas Canada Inc. Midstream n NGL processing and extraction plants; n transmission pipelines to transport natural gas and NGL; n natural gas gathering lines and field processing facilities; n purchase and sale of natural gas; n natural gas storage facilities; n liquefied petroleum gas (LPG) terminal; n natural gas and NGL marketing; n equity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents; n interest in a regulated pipeline in the Marcellus/Utica gas formation; and n sale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania. Power n natural gas-fired and distributed generation assets, certain of which are pending sale, whereby outputs are generally sold under power purchase agreements, both operational and under development; n energy storage; and n sale of power to residential, commercial, and industrial users in Washington D.C., Maryland, Virginia, Delaware, Pennsylvania, and Ohio. Corporate n the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of certain risk management contracts. The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 24 : Year Ended December 31, 2019 Utilities Midstream Power Corporate Total External revenue (note 24) $ 2,564.2 $ 1,574.3 $ 1,356.3 $ 0.2 $ 5,495.0 Intersegment revenue 26.6 6.9 10.9 — $ 44.4 Segment revenue $ 2,590.8 $ 1,581.2 $ 1,367.2 $ 0.2 $ 5,539.4 Year Ended December 31, 2018 Utilities Midstream Power Corporate Total External revenue (note 24) $ 1,752.6 $ 1,344.6 $ 1,162.0 $ (2.5 ) $ 4,256.7 Intersegment revenue 13.0 90.4 9.0 0.1 112.5 Segment revenue $ 1,765.6 $ 1,435.0 $ 1,171.0 $ (2.4 ) $ 4,369.2 Geographic Information Year Ended December 31 2019 2018 Revenue (a) Canada $ 1,244.8 $ 1,626.8 United States 4,325.5 2,553.0 TOTAL $ 5,570.3 $ 4,179.8 (a) Operating revenue from external customers, excluding unrealized gains (losses) or risk management contracts. As at December 31 2019 2018 Property, plant and equipment Canada $ 2,682.2 $ 2,348.2 United States 7,443.3 8,581.4 TOTAL $ 10,125.5 $ 10,929.6 The following tables show the composition by segment: Year Ended December 31, 2019 Utilities Midstream Power Corporate Intersegment Elimination (a) Total Segment revenue $ 2,590.8 $ 1,581.2 $ 1,367.2 $ 0.2 $ (44.4 ) $ 5,495.0 Cost of sales (1,117.9 ) (1,057.7 ) (1,084.4 ) — 32.9 (3,227.1 ) Operating and administrative (860.7 ) (249.1 ) (159.8 ) (40.6 ) 11.5 (1,298.7 ) Accretion expenses (0.1 ) (3.9 ) (1.1 ) — — (5.1 ) Depreciation and amortization (261.6 ) (92.1 ) (72.3 ) (12.0 ) — (438.0 ) Provisions on assets (note 6) — (35.2 ) (380.6 ) — — (415.8 ) Income from equity investments 18.3 122.4 0.4 — — 141.1 Other income (loss) 27.0 28.7 853.8 (1.4 ) — 908.1 Foreign exchange gains (losses) — (4.5 ) — 3.5 — (1.0 ) Interest expense — — — (345.8 ) — (345.8 ) Income (loss) before income taxes $ 395.8 $ 289.8 $ 523.2 $ (396.1 ) $ — $ 812.7 Net additions (reductions) to: Property, plant and equipment (b) $ 839.6 $ 350.3 $ (2,281.3 ) $ 1.2 $ — $ (1,090.2 ) Intangible assets $ 22.6 $ 4.9 $ — $ 9.0 $ — $ 36.5 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets. Year Ended December 31, 2018 Utilities Midstream Power Corporate Intersegment Elimination (a) Total Segment revenue $ 1,765.6 $ 1,435.0 $ 1,171.0 $ (2.4 ) $ (112.5 ) $ 4,256.7 Cost of sales (838.3 ) (976.4 ) (743.7 ) — 103.1 (2,455.3 ) Operating and administrative (727.4 ) (201.7 ) (159.1 ) (50.6 ) 9.8 (1,129.0 ) Accretion expenses (0.1 ) (4.0 ) (6.8 ) — — (10.9 ) Depreciation and amortization (165.8 ) (84.4 ) (130.5 ) (13.3 ) — (394.0 ) Provision on assets (note 6) (193.7 ) (153.7 ) (381.3 ) — — (728.7 ) Income (loss) from equity investments 7.2 51.1 (10.4 ) — — 47.9 Other income (loss) 4.5 0.7 (5.9 ) 2.0 (0.4 ) 0.9 Foreign exchange gains (losses) — (0.2 ) (0.1 ) 4.8 — 4.5 Interest expense (103.9 ) (10.6 ) (8.9 ) (185.6 ) — (309.0 ) Income (loss) before income taxes $ (251.9 ) $ 55.8 $ (275.7 ) $ (245.1 ) $ — $ (716.9 ) Net additions (reductions) to: Property, plant and equipment (b) $ 507.0 $ 383.4 $ (321.9 ) $ 4.0 $ — $ 572.5 Intangible assets $ 21.8 $ 4.7 $ 12.5 $ 6.7 $ — $ 45.7 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets. The following table shows goodwill and total assets by segment: Utilities Midstream Power Corporate Total As at December 31, 2019 Goodwill $ 3,573.0 $ 246.5 $ 122.6 $ — $ 3,942.1 Segmented assets $ 13,097.1 $ 5,471.4 $ 1,019.9 $206.1 $ 19,794.5 As at December 31, 2018 Goodwill $ 3,450.8 $ 426.4 $ 191.0 $ — $ 4,068.2 Segmented assets $ 12,991.3 $ 6,398.8 $ 3,814.7 $ 282.9 $ 23,487.7

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Subsequent events have been reviewed through February 27, 2020 , the date on which these audited Consolidated Financial Statements were issued. Segment Change During the first quarter of 2020, AltaGas began evaluating the structure of its business following asset sales that were completed as part of its 2019 asset monetization program. As a result of these changes, AltaGas has refocused on its core Utilities and Midstream segments and will no longer have a Power segment beginning in the first quarter of 2020. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, segmented financial information will be presented under the Utilities, Midstream, and Corporate/Other segments. The retail energy marketing operations for natural gas and electricity, which were previously included in the Midstream and Power segments, respectively, will be included within the Utilities segment, and other remaining Power assets will be included in within Corporate/Other. Petrogas Put Option On January 2, 2020, AltaGas advised that AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP) has received notice (the Put Notice) from SAM Holdings Ltd. (SAM) of its exercise of a put option (the Put Option) with respect to SAM's approximately one-third interest in Petrogas Energy Corp. (Petrogas). AIJVLP, a limited partnership owned 50 percent by AltaGas and 50 percent by Idemitsu Kosan Co., Ltd. (Idemitsu), owns the other approximately two-thirds of the outstanding common shares of Petrogas. Pursuant to the Petrogas unanimous shareholders agreement, a valid exercise of the Put Option by SAM after October 1, 2019, triggers a requirement for AIJVLP to purchase SAM's approximately one-third interest in Petrogas at the fair market value thereof, as determined by third-party valuators. AltaGas anticipates funding its portion of any such obligation with internal cash flow, the sale of remaining non-core assets and debt. Constitution Pipeline In February 2020, following evaluations of the diminished underlying economics for the proposed Constitution pipeline project, the partners of Constitution Pipeline Company, LLC elected not to proceed with the project. AltaGas held a 10 percent equity interest in Constitution. Upon the acquisition of WGL, AltaGas assigned a value of $ nil to Constitution.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
BASIS OF PRESENTATION	BASIS OF PRESENTATION These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). Pursuant to National Instrument 52‑107, "Acceptable Accounting Principles and Auditing Standards" (NI 52‑107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On July 13, 2018, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP.
PRINCIPLES OF CONSOLIDATION	PRINCIPLES OF CONSOLIDATION These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence, but not control, over are accounted for using the equity method. Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain equity method investments as well as consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage. The majority of AltaGas' HLBV investments were sold during 2019. All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non‑controlling interest in a subsidiary that AltaGas controls, that non‑controlling interest is reflected as “non‑controlling interests” in the Consolidated Financial Statements. The non‑controlling interests in net income (or loss) of consolidated subsidiaries are shown as an allocation of the consolidated net income (loss) and are presented separately in "net income (loss) applicable to non‑controlling interests".
USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY	USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates; determination as to whether a contract is or contains a lease; determination of the classification, term, and discount rate for leases; fair value of asset retirement obligations; fair value of property, plant and equipment and goodwill for impairment assessments; fair value of financial instruments; provisions for income taxes; assumptions used to measure employee future benefits; provisions for contingencies; purchase price allocations; and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.
Rate-Regulated Operations	Rate-Regulated Operations SEMCO Gas, ENSTAR, Washington Gas, and Hampshire Gas (collectively the Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia, and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD), and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively. Hampshire is regulated under a cost-of-service tariff by the Federal Energy Regulatory Commission (FERC). The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting, and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues, and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation. Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months.
Restricted Cash Holdings from Customers	Restricted Cash Holdings from Customers Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain Washington Gas executive and outside director retirement benefit plan obligations. The rabbi trust funds are invested in money market funds which are considered cash equivalents. These balances are included in "prepaid expenses and other current assets" and "long-term investments and other assets" in the Consolidated Balance Sheets.
Accounts Receivable	Accounts Receivable Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely.
Inventory	Inventory Inventory consists of materials, supplies, natural gas, natural gas liquids, renewable energy credits, and emission compliance instruments which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas.
Property, Plant and Equipment (PP&E), Depreciation and Amortization	Property, Plant, and Equipment (PP&E), Depreciation and Amortization Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight-line basis over the estimated useful life of the assets, with the exception of rate-regulated utilities assets, for which depreciation is calculated on a straight-line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities. The Utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs. Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas' prior quarter actual borrowing long-term interest rate. The Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate-regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses, and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators. The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 4 to 69 years Midstream assets 2 to 45 years Power generation assets 3 to 46 years Corporate assets 3 to 7 years As required by the regulatory authority, net additions to SEMCO's utility assets are amortized for one half-year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month after they are brought into active service. Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statements of Income (Loss) . Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statements of Income (Loss) .
Intangible Assets	Intangible Assets Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 to 19 years Electricity service agreements 2 to 60 years Software 3 to 10 years Land rights 5 to 64 years Franchises and consents 9 to 25 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 to 20 years The intangible assets recorded in the purchase price allocation for certain WGL commodity contracts are amortized based on the estimated fair value of the deliveries over the term of the contracts, which are over a period of 20 years .
Assets Held for Sale	Assets Held for Sale The Corporation classifies assets as held for sale when the carrying amount will be principally recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized.
Business Acquisitions	Business Acquisitions Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired. Management applies its best estimates and assumptions to determine the fair value of net assets acquired; however, the estimates are subject to further refinement of assumptions over a measurement period, which may be up to one year from the acquisition date. During the measurement period, adjustments to assets acquired and liabilities assumed may be recorded, with a corresponding impact to goodwill.
Provision on Assets	Provisions on Assets If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized. Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the fair value of the reporting unit will be compared to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its fair value and an impairment loss would be recorded in the Consolidated Statements of Income (Loss) .
Investments Accounted for by the Equity Method	Investments Accounted for by the Equity Method The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period. The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity's book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period. An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statements of Income (Loss) .
Financial Instruments	Financial Instruments Non-Utility Operations All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as "held-for-trading", "held-to-maturity", or "loans and receivables". Financial liabilities are classified as "held-for-trading" or other financial liabilities. Subsequent measurement is determined by classification. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Held-for-trading instruments include non-derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards, and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees. Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statements of Income (Loss) under " other income ". Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative, and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings. The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred. Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under "long-term investments and other assets" on the Consolidated Balance Sheets. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statements of Income (Loss) . Regulated Utility Operations All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income. Transaction costs for obtaining debt financing and reacquired debt costs are recorded as regulatory assets or liabilities, or as a reduction of the debt liability on the Consolidated Balance Sheets.
Weather-Related Instruments	Weather-Related Instruments WGL purchases certain weather-related instruments, such as heating degree day (HDD) derivatives and cooling degree day (CDD) derivatives to manage weather and price risks related to its natural gas and electricity sales. These derivatives are accounted for in accordance with ASC 815-45, Derivatives and Hedging – Weather Derivatives. For HDD derivatives, gains or losses are recognized when the actual HDD’s falls above or below the contractual HDD’s for each instrument. For CDD derivatives, gains or losses are recognized when the average temperature exceeds or is below a contractually stated level during the contract period. Refer to Note 23 for further discussion on weather-related instruments.
Hedges	Hedges As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate, and foreign exchange risk. AltaGas has designated certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815. Non-Utility Operations The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs. Regulated Utility Operations During planned issuances of debt securities, Washington Gas may utilize derivative instruments to manage the risk of interest-rate volatility. Gains and losses associated with these types of derivatives are recorded as regulatory liabilities or assets, and amortized in accordance with regulatory requirements, typically over the life of the related debt.
Debt	Debt AltaGas uses short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Short-term obligations are excluded from current liabilities if AltaGas has the ability and the intent to refinance these obligations on a long-term basis. The ability to refinance is primarily demonstrated through the availability of long-term revolving committed credit facilities in an amount equal to or greater than the expected maximum short-term obligation.
Asset Retirement Obligations	Asset Retirement Obligations AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations. There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates, as allowed by the regulators. These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980. Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators.
Revenue Recognition	Revenue Recognition AltaGas has revenue from various sources, including rate-regulated revenue, commodity sales, midstream service contracts, gas sales and transportation services, and gas storage services. For a detailed description of the Corporation’s revenue recognition policy by major source of revenue, please refer to Note 24 .
Foreign Currency Translation	Foreign Currency Translation Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statements of Income (Loss) . Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date. For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI. AltaGas may designate some of its U.S. dollar denominated long-term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long-term debt are included in OCI.
Share Options and Other Compensation Plans	Share Options and Other Compensation Plans Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity. AltaGas has a phantom unit plan (Phantom Plan, formerly the medium-term incentive plan) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas' common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash. The other portion of RU’s and PUs are valued at US $1 per unit. Upon vesting, the RUs and PUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2.4 dependent on the Corporation's performance relative to performance targets as approved by the Board of Directors. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs. In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers, and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers, and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, the participant is entitled to payment upon retirement, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs.
Pension Plans and Post-Retirement Benefits	Pension Plans and Post-Retirement Benefits AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs. The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees, expected health care costs, and other actuarial factors including discount rates and mortality. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs and credits are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 9.0 years and 13.2 years , respectively. AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability. For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.
Income Taxes	Income Taxes Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed, and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities. Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties. The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future.
Net Income (Loss) per Share	Net Income (Loss) per Share Basic net income (loss) per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards. The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation.
Contingencies	Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.
Leases - Lessee	Leases – Lessee AltaGas determines if an arrangement is a lease at inception. Operating leases are included in right-of-use (ROU) assets, current operating lease liabilities, and long-term operating lease liabilities in the Consolidated Balance Sheets. Finance leases are included in property, plant and equipment and current and long-term debt in the Consolidated Balance Sheets. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. AltaGas uses the rate implicit in the lease when readily determinable. When the implicit lease rate is not readily determinable, AltaGas uses its incremental borrowing rate to determine the present value of lease payments. AltaGas includes lessee options to renew or terminate the lease term in the determination of the ROU asset and lease liability when exercise is reasonably certain. The operating lease ROU asset is adjusted for lease payments made in advance of the commencement date, initial direct costs, and any lease incentives. Operating lease expense is recognized on a straight-line basis over the lease term in "operating and administrative expense". Depreciation and interest expense are recorded on finance leases.
Leases - Lessor	Leases – Lessor AltaGas determines if an arrangement is a lease at inception. Lease payments under an operating lease are recognized on a straight-line basis over the term of the lease. Variable lease payments are recognized as revenue as the facts and circumstances on which the variable lease payment is based occur. AltaGas does not include taxes assessed by governmental authorities, such as sales and related taxes, in the lease payments or variable lease payments.
Collaborative Agreements	Collaborative Arrangements WGL has collaborative arrangements with a third party to facilitate the asset optimization program. The collaborative arrangements allocate a tiered or fixed percentage of profits or losses to the third party as compensation for its participation.
ADOPTION OF NEW ACCOUNTING STANDARDS AND FUTURE CHANGES IN ACCOUNTING PRINCIPLES	ADOPTION OF NEW ACCOUNTING STANDARDS Effective January 1, 2019, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU): § ASU No. 2016-02 “Leases” and all related amendments (collectively “ASC 842”). AltaGas has applied ASC 842 using the modified retrospective approach as of the effective date of the new standard. Comparative information has not been restated and continues to be reported under the previous lease guidance ASC 840. AltaGas has applied the package of transition practical expedients which permitted the Corporation to not reassess (a) whether any expired or existing contracts contain leases, (b) lease classifications for any expired or existing leases, and (c) initial direct costs for any existing leases. In addition, AltaGas applied the transition practical expedient that permitted the Corporation to grandfather its accounting policy for land easements that existed as of, or expired, before January 1, 2019. The transition practical expedient to not separate lease and non-lease components for its building, office equipment, transportation equipment, and vehicle leases has been elected for lessee arrangements. The transition practical expedient to not separate lease and non-lease components for its lessor arrangements related to certain assets has also been elected. AltaGas has applied the short-term lease recognition exemption under which lease arrangements with a term of twelve months or less, including extension options that are reasonably certain of being exercised, are exempt from the recognition of a right-of-use asset and lease liability and recorded as an expense over the term of the lease. This exemption applies to all classes of assets. On adoption of ASC 842, all operating leases were recognized on the Consolidated Balance Sheets. The adoption resulted in an increase to long-term assets of approximately $181.0 million and an increase to long-term liabilities of approximately $170.5 million (net of the current portion that is recorded in current liabilities of approximately $23.3 million). The lease related liabilities were measured using the present value of the remaining minimum lease payments for existing leases discounted using the Corporation’s incremental borrowing rate as of January 1, 2019. For operating leases, the associated right-of-use assets were measured at the amount equal to the lease liabilities on January 1, 2019, adjusted for any prepaid or accrued lease payments and the remaining balance of any lease incentives received. The adoption of ASC 842 did not impact lessor accounting, the Consolidated Statements of Income (Loss), or the Consolidated Statements of Cash Flows. Please also refer to Note 10 of the Consolidated Financial Statements as at and for the year ended December 31, 2019 for further details; § ASU No. 2017-08 “Receivables – Nonrefundable Fees and Other Costs: Premium Amortization on Purchased Callable Debt Securities". The amendments in this ASU shorten the amortization period for certain callable debt securities held at a premium. Specifically, the amendments require the premium to be amortized to the earliest call date. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; § ASU No. 2017-11 “Earnings per Share and Derivatives and Hedging – Distinguishing Liabilities from Equity: Accounting for Certain Financial Instruments with Down Round Features, Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception”. The amendments in this ASU simplify the accounting for certain equity-linked financial instruments and embedded features with down round features that reduce the exercise price when pricing of a future round of financing is lower. The amendments in this ASU also require entities that present earnings per share under ASC 260 to recognize the effect of a down round feature in a freestanding equity-classified financial instrument only when it is triggered. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; § ASU No. 2018-07 “Compensation – Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting”. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees, with the objective of making the measurement consistent with employee share based payment awards. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; § ASU No. 2018-08 “Not-for-Profit-Entities – Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this ASU clarify whether a transfer of assets is a contribution or an exchange transaction. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; § ASU No. 2018-15 “Intangibles – Goodwill and Other – Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement (CCA) that is a Service Contract”. The amendments in this ASU align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal use software license). The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and § ASU No. 2018-16 “Derivatives and Hedging: Inclusion of the Second Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in this ASU permit the use of Overhead Index Swap (OIS) rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements. FUTURE CHANGES IN ACCOUNTING PRINCIPLES In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas will adopt this standard on January 1, 2020 using a modified-retrospective approach through a cumulative-effect adjustment to retained earnings. AltaGas has completed scoping and evaluation activities for this new accounting standard, and has quantified the impact of this ASU on its opening Consolidated Balance Sheet as at January 1, 2020. Upon adoption, "accounts receivable, net of allowances" is expected to decrease by less than 1 percent of the outstanding accounts receivable balance, with an offsetting increase to "accumulated deficit". In August 2018, FASB issued ASU No. 2018-13 “Fair Value Measurement – Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In August 2018, FASB issued ASU No. 2018-14 “Compensation-Retirement Benefits-Defined Benefit Plans – General: Disclosure Framework – Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other post-retirement plans. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In October 2018, FASB issued ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this ASU provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interest held through related parties under common control will be considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. An entity should apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In March 2019, FASB issued ASU No. 2019-01 “Leases: Codification Improvements”. The amendments in this ASU provide a fair value exception for lessors that are not manufacturers or dealers, clarify the presentation of principal payments received under sales-type and direct finance leases on the statements of cash flows, and clarify transition disclosure requirements for the adoption of ASC 842. The amendments on the fair value exception and on the presentation on the statement of cash flows are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The amendment on the transition disclosure requirement is effective upon adoption of ASC 842. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In April 2019, FASB issued ASU No. 2019-04 “Financial Instruments - Credit Losses, Derivatives and Hedging, and Codification Improvements”. The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards on credit losses (ASU 2016-13), hedging (ASU 2017-12), and recognizing and measuring financial instruments (ASU 2016-01). The amendments related to credit losses have the same effective date and transition requirements as ASU 2016-13, the amendments related to hedge accounting are effective as of the beginning of the first annual period beginning after issuance of this ASU and may be applied retrospectively to the date ASU 2017-12 was adopted or prospectively with some exceptions, and the amendments related to financial instruments are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In May 2019, FASB issued ASU No. 2019-05 “Financial Instruments - Credit Losses: Targeted Transition Relief". The amendments in this ASU provide entities that have certain instruments within the scope of Subtopic 326-20 - Financial Instruments - Credit Losses - Measured at Amortized Cost (other than held-to-maturity debt securities) a one-time irrevocable option to elect fair value treatment on an eligible instrument-by-instrument basis. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In November 2019, FASB issued ASU No. 2019-11 "Financial Instruments - Credit Losses: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in ASU 2016-13. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In December 2019, FASB issued ASU No. 2019-12 "Income Taxes: Simplifying the Accounting for Income Taxes". The amendments in this ASU simplify the accounting for income taxes by clarifying certain aspects of current guidance and removing some exceptions to the general principles in ASC 740. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas is assessing the impact of this ASU on its consolidated financial statements.

(Tables)

(Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Estimated Useful Lives of Property, Plant and Equipment	The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 4 to 69 years Midstream assets 2 to 45 years Power generation assets 3 to 46 years Corporate assets 3 to 7 years As at December 31, 2019 December 31, 2018 Cost Accumulated Net book Cost Accumulated Net book Utilities $ 7,316.1 $ (155.0 ) $ 7,161.1 $ 7,090.5 $ (89.7 ) $ 7,000.8 Midstream 3,182.0 (585.4 ) 2,596.6 3,178.2 (845.7 ) 2,332.5 Power 976.7 (594.6 ) 382.1 4,633.9 (1,858.3 ) 2,775.6 Corporate 49.5 (40.9 ) 8.6 49.4 (39.1 ) 10.3 Reclassified to assets held for sale (25.2 ) 2.3 (22.9 ) (2,999.3 ) 1,809.7 (1,189.6 ) $ 11,499.1 $ (1,373.6 ) $ 10,125.5 $ 11,952.7 $ (1,023.1 ) $ 10,929.6
Summary of Estimated Useful Lives of Finite-Lived Intangible Assets	The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 to 19 years Electricity service agreements 2 to 60 years Software 3 to 10 years Land rights 5 to 64 years Franchises and consents 9 to 25 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 to 20 years As at December 31, 2019 December 31, 2018 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26.6 $ (15.2 ) $ 11.4 $ 26.6 $ (14.3 ) $ 12.3 Electricity service agreements 8.5 (7.8 ) 0.7 269.5 (25.9 ) 243.6 Energy services relationships 91.6 (27.4 ) 64.2 176.1 (33.8 ) 142.3 Software 303.7 (101.2 ) 202.5 293.9 (77.7 ) 216.2 Land rights 1.1 (0.1 ) 1.0 1.4 (0.2 ) 1.2 Commodity contracts 327.1 (21.3 ) 305.8 346.3 (6.3 ) 340.0 Franchises and consents — — — 5.0 — 5.0 Reclassified to assets held for sale (note 5) — — — (277.4 ) 28.7 (248.7 ) $ 758.6 $ (173.0 ) $ 585.6 $ 841.4 $ (129.5 ) $ 711.9

Acquisition of WGL Holdings, _2

Acquisition of WGL Holdings, Inc. (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Schedule of Final Purchase Price Allocation	Purchase consideration $ 5,973 Fair value assigned to net assets Current assets $ 1,220 Property, plant and equipment 5,884 Intangible assets 577 Regulatory assets 408 Long-term investments 1,475 Other long-term assets 462 Current liabilities (1,916 ) Long-term debt (2,548 ) Preferred shares (41 ) Regulatory liabilities (1,126 ) Deferred income taxes (741 ) Other long-term liabilities (959 ) Non-controlling interest (9 ) Accumulated other comprehensive income (2 ) Fair value of net assets acquired $ 2,684 Goodwill $ 3,289

Assets Held For Sale (Tables)

Assets Held For Sale (Tables)	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Assets Held for Sale	As at December 31, 2019 December 31, 2018 Assets held for sale Cash $ — $ 4.9 Accounts receivable — 85.2 Inventory — 0.5 Property, plant and equipment 22.9 1,189.6 Intangible assets — 248.7 Operating right-of-use assets 0.4 — Goodwill 1.0 — Other long-term assets 3.2 — $ 27.5 $ 1,528.9 Liabilities associated with assets held for sale Accounts payable and accrued liabilities $ — $ 23.8 Asset retirement obligations 0.2 10.8 Unamortized investment tax credits 3.2 — Operating lease liabilities - long-term 0.4 — Other long-term liabilities — 136.8 $ 3.8 $ 171.4

Provisions on Assets (Tables)

Provisions on Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Provisions on Assets	Year Ended December 31 2019 2018 Utilities $ — $ 193.7 Midstream 35.2 153.7 Power 380.6 381.3 $ 415.8 $ 728.7

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Schedule of Inventory	As at December 31 2019 2018 Natural gas held in storage (a) $ 359.0 $ 418.0 Materials and supplies 56.3 53.3 Renewable energy credits and emission compliance instruments 64.1 38.2 Natural gas liquids 26.2 6.4 $ 505.6 $ 515.9 (a) As at December 31, 2019 , $214.3 million of the natural gas held in storage was held by rate-regulated utilities ( 2018 - $270.4 million ).

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 4 to 69 years Midstream assets 2 to 45 years Power generation assets 3 to 46 years Corporate assets 3 to 7 years As at December 31, 2019 December 31, 2018 Cost Accumulated Net book Cost Accumulated Net book Utilities $ 7,316.1 $ (155.0 ) $ 7,161.1 $ 7,090.5 $ (89.7 ) $ 7,000.8 Midstream 3,182.0 (585.4 ) 2,596.6 3,178.2 (845.7 ) 2,332.5 Power 976.7 (594.6 ) 382.1 4,633.9 (1,858.3 ) 2,775.6 Corporate 49.5 (40.9 ) 8.6 49.4 (39.1 ) 10.3 Reclassified to assets held for sale (25.2 ) 2.3 (22.9 ) (2,999.3 ) 1,809.7 (1,189.6 ) $ 11,499.1 $ (1,373.6 ) $ 10,125.5 $ 11,952.7 $ (1,023.1 ) $ 10,929.6

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Summary of Intangible Assets	The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 to 19 years Electricity service agreements 2 to 60 years Software 3 to 10 years Land rights 5 to 64 years Franchises and consents 9 to 25 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 to 20 years As at December 31, 2019 December 31, 2018 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26.6 $ (15.2 ) $ 11.4 $ 26.6 $ (14.3 ) $ 12.3 Electricity service agreements 8.5 (7.8 ) 0.7 269.5 (25.9 ) 243.6 Energy services relationships 91.6 (27.4 ) 64.2 176.1 (33.8 ) 142.3 Software 303.7 (101.2 ) 202.5 293.9 (77.7 ) 216.2 Land rights 1.1 (0.1 ) 1.0 1.4 (0.2 ) 1.2 Commodity contracts 327.1 (21.3 ) 305.8 346.3 (6.3 ) 340.0 Franchises and consents — — — 5.0 — 5.0 Reclassified to assets held for sale (note 5) — — — (277.4 ) 28.7 (248.7 ) $ 758.6 $ (173.0 ) $ 585.6 $ 841.4 $ (129.5 ) $ 711.9
Summary of Estimated Amortization Expense of Intangible Assets	The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with an indefinite life, for the years ended December 31: 2020 $ 79.1 2021 $ 70.6 2022 $ 69.7 2023 $ 62.3 2024 $ 24.2 Thereafter $ 95.2

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Components of Lease cost	The components of lease expense were as follows: Year Ended Operating lease cost (includes variable lease payments) $ 29.2 Finance lease cost Amortization of right-of-use assets $ 3.4 Interest on lease liabilities 0.3 Total finance lease cost $ 3.7 Total lease cost $ 32.9 Supplemental cash flow information related to leases was as follows: Year Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from finance leases $ (0.3 ) Operating cash flows from operating leases $ (20.6 ) Financing cash flows from finance leases (a) $ (3.7 ) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 50.4 Finance leases $ 5.4 (a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows. As at December 31, 2019 Weighted average remaining lease term (years) Operating leases 10.9 Finance leases 5.2 Weighted average discount rate (%) Operating leases 3.51 Finance leases 3.68
Supplemental Balance Sheet Location	Supplemental balance sheet information related to leases was as follows: As at December 31, 2019 Operating Leases Operating lease right-of-use assets Long-term $ 169.8 Included in assets held for sale (note 5) 0.4 Total operating lease right-of-use assets $ 170.2 Operating lease liabilities Current $ (27.3 ) Long-term (153.4 ) Included in liabilities associated with assets held for sale (note 5) (0.4 ) Total operating lease liabilities $ (181.1 ) Finance Leases Property and equipment, gross $ 13.2 Accumulated depreciation (3.3 ) Property and equipment, net $ 9.9 Current portion of long-term debt $ (3.5 ) Long-term debt (6.4 ) Total finance lease liabilities $ (9.9 )
Operating Lease Liability, Future Minimum Payments	Maturity analysis of lease liabilities was as follows: Operating Leases Finance Leases 2020 $ 27.8 $ 3.5 2021 27.1 2.9 2022 26.5 2.0 2023 24.5 1.1 2024 20.1 0.4 Thereafter 100.1 2.0 Total lease payments 226.1 11.9 Less: imputed interest (45.0 ) (2.0 ) Total $ 181.1 $ 9.9
Finance Lease Liability, Future Minimum Payments	Maturity analysis of lease liabilities was as follows: Operating Leases Finance Leases 2020 $ 27.8 $ 3.5 2021 27.1 2.9 2022 26.5 2.0 2023 24.5 1.1 2024 20.1 0.4 Thereafter 100.1 2.0 Total lease payments 226.1 11.9 Less: imputed interest (45.0 ) (2.0 ) Total $ 181.1 $ 9.9
Maturity Analysis of Lease Receivables	Maturity analysis of lease receivables was as follows: Operating Leases 2020 $ 118.3 2021 115.4 2022 115.6 2023 115.9 2024 47.8 Thereafter 477.5 Total $ 990.5

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	As at December 31, December 31, Balance, beginning of year $ 4,068.2 $ 817.3 Provisions on assets — (124.2 ) Business acquisition (note 3) — 3,196.4 Adjustment to goodwill on business acquisition (note 3) 92.2 — Goodwill included in dispositions (note 4) (29.1 ) — Reclassified to assets held for sale (note 5) (1.0 ) — Foreign exchange translation (188.2 ) 178.7 Balance, end of year $ 3,942.1 $ 4,068.2

Long-Term Investments and Oth_2

Long-Term Investments and Other Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Investments, All Other Investments [Abstract]
Schedule of Long-Term and Other Investments	As at December 31, December 31, Investments in publicly-traded entities $ 4.3 $ 8.4 Loan to affiliate 45.0 45.0 Deferred lease receivable 17.4 24.4 Debt issuance costs associated with credit facilities 6.2 7.9 Refundable deposits 8.9 16.2 Prepayment on long-term service agreements 80.6 82.5 Cash calls from joint venture partners 9.5 — Contract asset (note 24) 30.0 11.5 Rabbi trust (notes 28 and 31) 32.0 61.7 Other long-term receivables (note 29) 33.1 — Other 29.5 25.5 $ 296.5 $ 283.1

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2019
VARIABLE INTEREST ENTITIES [Abstract]
Schedule of VIE Amounts in Consolidated Balance Sheets	The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs: As at December 31, 2019 December 31, 2018 Current assets $ 6.4 $ 1,383.5 Property, plant and equipment 371.1 619.2 Long-term investments and other assets 53.3 48.0 Operating right-of-use assets 0.1 — Current liabilities (3.6 ) (161.8 ) Asset retirement obligations (3.3 ) (0.9 ) Other long-term liabilities (0.1 ) (3.0 ) Net assets $ 423.9 $ 1,885.0

Investments Accounted for by _2

Investments Accounted for by the Equity Method (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Method Investments	Carrying value as at December 31 Equity income (loss) for the year ended December 31 Description Location Ownership Percentage 2019 2018 2019 2018 AltaGas Canada Inc. (ACI) (a) Canada 37 $ 163.9 $ 112.5 $ 17.0 $ 5.4 AltaGas Idemitsu Joint Venture LP Canada 50 431.3 342.9 62.5 2.1 Constitution Pipeline, LLC (Constitution) (b) United States 10 0.1 — (0.5 ) (0.2 ) Craven County Wood Energy LP (c) United States 50 — 7.8 0.1 (14.1 ) Eaton Rapids Gas Storage System United States 50 27.0 29.4 1.3 2.0 Grayling Generating Station LP (c) United States 50 — 29.0 0.3 3.6 Inuvik Gas Ltd. (d) Canada 33 — — — (0.2 ) Meade Pipeline Co. LLC (c) (e) United States 55 — 757.8 (3.6 ) 12.2 Mountain Valley Pipeline, LLC (Mountain Valley) (f) United States 10 671.3 532.5 42.8 11.5 Sarnia Airport Storage Pool LP Canada 50 18.0 18.7 1.0 1.0 Petrogas Preferred Shares Canada n/a 150.0 150.0 12.8 12.8 Stonewall Gas Gathering Systems LLC (c) United States 30 — 411.8 7.4 11.8 $ 1,461.6 $ 2,392.4 $ 141.1 $ 47.9 (a) As at December 31, 2019 , the aggregate market value of AltaGas' investment in ACI was $367.9 million ( 11,025,000 shares at the quoted closing market price of $33.37 on December 31, 2019 ). As at December 31, 2018 , the aggregate market value was $178.8 million ( 11,025,000 shares at the quoted closing market price of $16.22 on December 31, 2018 ). (b) The equity method is considered appropriate because Constitution is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. In February 2020, the partners of Constitution elected not to proceed with the pipeline project (Note 33). (c) Disposed of in 2019 (Note 4 ). (d) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018. (e) Meade was a VIE prior to disposition in November 2019 (Notes 4 and 13 ). (f) The equity method is considered appropriate because Mountain Valley is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies.
Schedule of Combined Financial Information of Equity Method Investments	Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows (a) : Year Ended December 31 2019 2018 Revenues $ 1,109.3 $ 351.6 Expenses (355.0 ) (142.7 ) $ 754.3 $ 208.9 As at December 31 2019 2018 Current assets $ 411.1 $ 1,204.6 Property, plant and equipment $ 8,033.8 $ 7,602.5 Intangible assets $ 21.9 $ 22.9 Long-term investments and other assets $ 1,458.8 $ 1,326.6 Current liabilities $ (393.8 ) $ (1,015.2 ) Other long-term liabilities $ (992.1 ) $ (949.6 ) (a) For equity investments that were disposed of in the year (Note 4 ), revenues and expenses reflect the period prior to disposition and balance sheet amounts as at December 31 are $nil.

Short-term Debt (Tables)

Short-term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Short-Term Debt	As at December 31, December 31, Bank indebtedness $ — $ 0.2 Commercial paper (a) 389.0 1,145.2 Project financing 71.0 64.5 $ 460.0 $ 1,209.9 (a) WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. As at December 31, 2019, certain commercial paper balances have been classified as long-term debt as they are supported by long-term extendible committed credit facilities with maturities ranging from 2022 to 2024 (see Note 16 ).

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	As at Maturity date December 31, December 31, Credit facilities $1,400 million unsecured extendible revolving facility (a) 15-May-2023 $ 89.6 $ 964.7 US$300 million unsecured extendible revolving facility (b) 15-May-2022 — 287.8 Acquisition credit facility (c) 6-Jan-2020 — 113.2 US$1,200 million unsecured revolving credit facility (d) 28-Dec-2021 — 1,637.0 US$300 million unsecured term facility 27-Feb-2021 389.6 — US$150 million unsecured extendible revolving facility 20-Dec-2023 163.5 — Commercial paper (e) Various 367.4 — AltaGas Ltd. medium-term notes (MTNs) $200 million Senior unsecured - 4.55 percent 17-Jan-2019 — 200.0 $200 million Senior unsecured - 4.07 percent 1-Jun-2020 200.0 200.0 $350 million Senior unsecured - 3.72 percent 28-Sep-2021 350.0 350.0 $500 million Senior unsecured - 2.61 percent 16-Dec-2022 500.0 — $300 million Senior unsecured - 3.57 percent 12-Jun-2023 300.0 300.0 $200 million Senior unsecured - 4.40 percent 15-Mar-2024 200.0 200.0 $300 million Senior unsecured - 3.84 percent 15-Jan-2025 300.0 299.9 $350 million Senior unsecured - 4.12 percent 7-Apr-2026 349.9 349.8 $200 million Senior unsecured - 3.98 percent 4-Oct-2027 199.9 199.9 $100 million Senior unsecured - 5.16 percent 13-Jan-2044 100.0 100.0 $300 million Senior unsecured - 4.50 percent 15-Aug-2044 299.8 299.8 $250 million Senior unsecured - 4.99 percent 4-Oct-2047 250.0 250.0 WGL and Washington Gas MTNs US$450 million Senior unsecured - 2.25 to 4.76 percent (f) Nov 2019 — 682.1 US$250 million Senior unsecured - 2.44 percent (g) 12-Mar-2020 324.7 341.1 US$20 million Senior unsecured - 6.65 percent 20-Mar-2023 26.0 27.3 US$40.5 million Senior unsecured - 5.44 percent 11-Aug-2025 52.6 55.3 US$53 million Senior unsecured - 6.62 to 6.82 percent Oct - 2026 68.8 72.3 US$72 million Senior unsecured - 6.40 to 6.57 percent Feb - Sep 2027 93.5 98.2 US$52 million Senior unsecured - 6.57 to 6.85 percent Jan - Mar 2028 67.5 70.9 US$8.5 million Senior unsecured - 7.50 percent 1-Apr-2030 11.0 11.6 US$50 million Senior unsecured - 5.70 to 5.78 percent Jan - Mar 2036 64.9 68.2 US$75 million Senior unsecured - 5.21 percent 3-Dec-2040 97.4 102.3 US$75 million Senior unsecured - 5.00 percent 15-Dec-2043 97.4 102.3 US$300 million Senior unsecured - 4.22 to 4.60 percent Sep - Dec 2044 389.6 409.3 US$450 million Senior unsecured - 3.80 percent 15-Sep-2046 584.5 613.9 US$300 million Senior unsecured - 3.65 percent 16-Sep-2049 389.6 — SEMCO long-term debt US$300 million SEMCO Senior Secured - 5.15 percent (h) 21-Apr-2020 389.6 409.3 US$82 million SEMCO Senior Secured - 4.48 percent (i) 2-Mar-2032 76.1 86.3 Fair value adjustment on WGL Acquisition (note 3) 84.3 89.0 Finance lease liabilities (note 10) 9.9 0.8 $ 6,887.1 $ 8,992.3 Less debt issuance costs (36.4 ) (35.2 ) $ 6,850.7 $ 8,957.1 Less current portion (922.9 ) (890.2 ) $ 5,927.8 $ 8,066.9 (a) Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers' acceptances, or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made. (b) Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, LIBOR loans, or letters of credit. (c) The acquisition facility was repaid in full and canceled on February 1, 2019. (d) Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, or LIBOR loans. (e) Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024 . (f) Certain MTNs have a floating rate per annum reset quarterly based on terms set forth in the prospectus supplement filed by WGL pursuant to Securities Act Rule 424 on November 27, 2017. (g) Floating rate per annum reset quarterly based on terms set forth in the prospectus filed by WGL pursuant to Securities Act Rule 424 on March 13, 2018. (h) Collateral for the U.S. dollar MTNs is certain SEMCO assets. (i) Collateral for the CINGSA Senior secured loan is certain CINGSA assets. Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Asset Retirement Obligations	As at December 31 2019 2018 Balance, beginning of year $ 500.6 $ 88.3 Obligations acquired (note 3) — 399.1 New obligations 7.0 3.3 Obligations settled (2.5 ) (4.2 ) Disposals (6.2 ) (1.6 ) Revision in estimated cash flow (128.5 ) 3.8 Accretion expense (a) 18.9 12.3 Foreign exchange translation (20.7 ) 20.3 Reclassified to liabilities associated with assets held for sale (note 5) (0.2 ) (10.8 ) Total $ 368.4 $ 510.5 Less current portion (included in accounts payable and accrued liabilities) (6.4 ) (9.9 ) Balance, end of year $ 362.0 $ 500.6 (a) Certain amounts relating to Utility asset retirement obligations are recorded through regulatory assets or liabilities on the Consolidated Balance Sheets due to regulatory treatment. The remaining portion is recorded through the Consolidated Statements of Income (Loss) .

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Schedule of Other Long-Term Liabilities	As at December 31, December 31, Deferred lease payable $ — $ 13.1 Deferred revenue 4.0 3.9 Customer advances for construction 63.9 58.6 Sundance B PPAs termination expense (a) — 2.0 Lease inducement — 2.7 Merger commitments 14.0 21.4 Other long-term liabilities 19.9 20.3 $ 101.8 $ 122.0 (a) In 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B Power Purchase Arrangements (PPAs). Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which has been recorded under “accounts payable and accrued liabilities”.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Income Tax Provision	Year Ended December 31 2019 2018 Income (loss) before income taxes - consolidated $ 812.7 $ (716.9 ) Statutory income tax rate (%) 26.5 27.0 Expected taxes at statutory rates $ 215.4 $ (193.6 ) Add (deduct) the tax effect of: Permanent differences $ 10.9 $ (1.0 ) Statutory and other rate differences (51.6 ) (19.6 ) Rate adjustment for change in tax rates (10.7 ) 1.3 Deferred income tax recovery on regulated assets (24.8 ) (7.3 ) Tax differences on divestitures and transactions (158.2 ) (32.3 ) Non-controlling interests 3.5 4.7 Change in valuation allowance (11.1 ) (22.3 ) Other (1.0 ) 6.9 $ (27.6 ) $ (263.2 ) Income tax provision Current Canada $ 26.7 $ 23.7 United States 36.6 0.7 $ 63.3 $ 24.4 Deferred Canada $ 11.6 $ (166.1 ) United States (102.5 ) (121.5 ) $ (90.9 ) $ (287.6 ) Effective income tax rate (%) (3.4 ) 36.7
Schedule of Deferred Income Tax Liabilities	Net deferred income tax liabilities were composed of the following: As at December 31, December 31, PP&E and intangible assets $ 1,450.6 $ 1,764.6 Regulatory assets (204.1 ) (166.3 ) Tax pools, deferred financing, and compensation (138.2 ) (453.6 ) Other (161.2 ) (209.9 ) Valuation allowance 12.0 23.1 $ 959.1 $ 957.9
Schedule of Uncertain Tax Positions	Management determined that the following provision was required for uncertainty on income taxes during the year: Year Ended December 31 2019 2018 Balance, beginning of year $ 2.2 $ 5.9 Net changes during the year (0.2 ) (3.7 ) Balance, end of year $ 2.0 $ 2.2

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as at December 31, 2019 and 2018 , over which the Corporation expects to realize or settle the assets or liabilities: As at December 31 2019 2018 Recovery Period Regulatory assets - current Deferred cost of gas (a) $ 7.6 $ 20.4 Less than one year Accelerated replacement recovery mechanisms (b) 2.5 — Less than one year Interruptible sharing (a) 2.7 0.6 Less than one year $ 12.8 $ 21.0 Regulatory assets - non-current Deferred regulatory costs (a) (c) $ 149.5 $ 215.5 1 - 51 year s Future recovery of pension and other retirement benefits (a) 128.2 192.9 Various Future recovery of non-retirement employee benefits (a) (d) 19.4 21.3 Various Deferred pension costs (e) — 7.8 — Deferred environmental costs (a) (f) 17.7 19.9 Various Deferred loss on debt transactions and derivative instruments (a) (g) 99.2 109.3 Various Deferred future income taxes (a) (h) 42.7 67.0 Various Energy efficiency program - Maryland (i) 12.1 4.6 Various Other 17.9 24.7 Various $ 486.7 $ 663.0 Regulatory liabilities - current Deferred cost of gas (a) $ 60.2 $ 71.2 Less than one year Refundable tax credit (j) 1.9 3.8 Less than one year Federal income tax rate change (k) 33.1 26.2 Less than one year Virginia rate refund (l) 40.4 — Less than one year Accelerated replacement recovery mechanisms (b) 0.4 5.2 Less than one year Interruptible sharing (a) 0.4 2.3 Less than one year Other 9.1 6.2 Less than one year $ 145.5 $ 114.9 Regulatory liabilities - non-current Refundable tax credit (j) 3.9 6.1 2 years Future expense of pension and other retirement benefits (a) 261.2 166.7 Various Future removal and site restoration costs (m) 483.9 514.7 Various Deferred gain on debt transactions and derivative instruments (a) (g) 1.6 1.8 Various Federal income tax rate change (k) 628.3 698.4 Various Other 4.3 5.1 Various $ 1,383.2 $ 1,392.8 (a) Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions. (b) Represents amounts for deferred over or under collections of surcharges associated with Washington Gas' accelerated pipeline recovery programs in the District of Columbia, Maryland, and Virginia. (c) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled. (d) Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates. Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator. (e) In 2018, this balance related to previously deferred pension and other post-retirement benefits expenses that were fully amortized in 2019. (f) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates. (g) The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior fiscal years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. As at December 31, 2019 , this also includes a fair value adjustment of $79.8 million ( December 31, 2018 - $87.3 million ) recorded on the WGL Acquisition (Note 3 ). (h) This balance reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates. (i) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland. (j) On September 18, 2013, CINGSA received a US $15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA's customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology. (k) The Tax Cuts and Jobs Act (TCJA) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities in 2018 to the lower federal corporate tax rate of 21 percent , resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers. (l) Represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2019 Virginia rate case. (m) This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Accumulated Other Comprehensive Income	($ millions) Available-for-sale Defined benefit pension and PRB plans Hedge net investments Translation foreign operations Equity investee Total Opening balance, January 1, 2019 $ — $ (19.0 ) $ (209.2 ) $ 801.4 $ 5.8 $ 579.0 OCI before reclassification — 15.2 68.2 (406.2 ) (0.7 ) (323.5 ) Amounts reclassified from OCI — 1.1 — — — 1.1 Current period OCI (pre-tax) — 16.3 68.2 (406.2 ) (0.7 ) (322.4 ) Income tax on amounts retained in AOCI — (3.2 ) (8.2 ) — — (11.4 ) Income tax on amounts reclassified to earnings — (0.3 ) — — — (0.3 ) Net current period OCI — 12.8 60.0 (406.2 ) (0.7 ) (334.1 ) Ending balance, December 31, 2019 $ — $ (6.2 ) $ (149.2 ) $ 395.2 $ 5.1 $ 244.9 Opening balance, January 1, 2018 $ (7.1 ) $ (11.4 ) $ (129.0 ) $ 342.9 $ 3.7 $ 199.1 OCI before reclassification — (14.1 ) (90.6 ) 458.5 2.1 355.9 Amounts reclassified from AOCI — 0.7 — — — 0.7 Adoption of ASU No. 2016-01 7.1 — — — — 7.1 Curtailment of DB and PRB plan — 4.2 — — — 4.2 Current period OCI (pre-tax) 7.1 (9.2 ) (90.6 ) 458.5 2.1 367.9 Income tax on amounts retained in AOCI — 3.3 10.4 — — 13.7 Income tax on amounts reclassified to earnings — (0.2 ) — — — (0.2 ) Income tax on amounts related to curtailment of DB and PRB plan — (1.5 ) — — — (1.5 ) Net current period OCI 7.1 (7.6 ) (80.2 ) 458.5 2.1 379.9 Ending balance, December 31, 2018 $ — $ (19.0 ) $ (209.2 ) $ 801.4 $ 5.8 $ 579.0
Summary of Reclassification from Accumulated Other Comprehensive Income	Reclassification From Accumulated Other Comprehensive Income AOCI components reclassified Income statement line item Year Ended December 31, 2019 Year Ended Defined benefit pension and PRB plans Other income $ 1.1 $ 0.7 Deferred income taxes Income tax expense – deferred (0.3 ) (0.2 ) $ 0.8 $ 0.5

Financial Instruments and Fin_2

Financial Instruments and Financial Risk Management (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Fair Value of Risk Management Assets and Liabilities	As at December 31, 2019 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income (a) Risk management assets - current $ 81.4 $ — $ 30.4 $ 51.0 $ 81.4 Risk management assets - non-current 30.9 — 6.7 24.2 30.9 Equity securities (b) 4.3 4.3 — — 4.3 Fair value through regulatory assets (a) Risk management assets - current 5.2 — — 5.2 5.2 Risk management assets - non-current 8.2 — 0.4 7.8 8.2 Amortized cost Loans and receivables (b) 45.0 — 46.1 — 46.1 $ 175.0 $ 4.3 $ 83.6 $ 88.2 $ 176.1 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 120.6 $ — $ 98.7 $ 21.9 $ 120.6 Risk management liabilities - non-current 77.0 — 19.2 57.8 77.0 Fair value through regulatory liabilities (a) Risk management liabilities - current 4.2 — 0.6 3.6 4.2 Risk management liabilities - non-current 90.0 — — 90.0 90.0 Amortized cost Current portion of long-term debt 922.9 — 922.9 — 922.9 Long-term debt 5,927.8 — 6,263.8 — 6,263.8 Other current liabilities (c) 15.4 — 15.4 — 15.4 $ 7,157.9 $ — $ 7,320.6 $ 173.3 $ 7,493.9 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (c) Excludes non-financial liabilities. As at December 31, 2018 Carrying Level 1 Level 2 Level 3 Total Financial assets Fair value through net income (a) Risk management assets - current $ 99.0 $ — $ 68.3 $ 30.7 $ 99.0 Risk management assets - non-current 49.0 — 18.0 31.0 49.0 Equity securities (b) 8.4 8.4 — — 8.4 Fair value through regulatory assets (a) Risk management assets - current 15.1 — 2.7 12.4 15.1 Risk management assets - non-current 8.7 — — 8.7 8.7 Amortized cost Loans and receivables (b) 45.0 — 45.2 — 45.2 $ 225.2 $ 8.4 $ 134.2 $ 82.8 $ 225.4 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 72.0 $ — $ 41.3 $ 30.7 $ 72.0 Risk management liabilities - non-current 103.4 — 15.3 88.1 103.4 Fair value through regulatory liabilities (a) Risk management liabilities - current 17.3 — 2.9 14.4 17.3 Risk management liabilities - non-current 109.6 — 0.1 109.5 109.6 Amortized cost Current portion of long-term debt 890.2 — 884.4 — 884.4 Long-term debt 8,066.9 — 8,040.3 — 8,040.3 Other current liabilities (c) 11.2 — 11.2 — 11.2 Other long-term liabilities (c) 2.0 — 2.0 — 2.0 $ 9,272.6 $ — $ 8,997.5 $ 242.7 $ 9,240.2 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (c) Excludes non‑financial liabilities.
Quantitative Information About the Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3	The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments as at December 31, 2019 : Net Fair Value Valuation Technique Unobservable Inputs Range Natural gas $ (83.8 ) Discounted Cash Flow Natural Gas Basis Price (per dekatherm) $ (1.18 ) - $ 3.27 Natural gas $ (1.4 ) Option Model Natural Gas Basis Price (per dekatherm) $ (1.19 ) - $ 3.30 Annualized Volatility of Spot Market Natural Gas 29 % - 906 % Electricity $ 0.1 Discounted Cash Flow Electricity Congestion Price (per megawatt hour) $ (6.73 ) - $ 65.26
Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3	The following tables provide a reconciliation of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy: For the year ended December 31 2019 2018 Natural Electricity Total Natural Electricity Total Balance, beginning of year $ (148.5 ) $ (14.7 ) $ (163.2 ) $ — $ — $ — Acquired (note 3) — — — (136.1 ) (10.6 ) (146.7 ) Realized and unrealized gains (losses): Recorded in income 47.6 1.4 49.0 (8.3 ) (6.5 ) (14.8 ) Recorded in regulatory assets 23.6 — 23.6 (5.9 ) — (5.9 ) Transfers into Level 3 (9.0 ) — (9.0 ) — — — Transfers out of Level 3 12.3 — 12.3 7.3 — 7.3 Purchases — (11.4 ) (11.4 ) — 6.4 6.4 Settlements (17.1 ) 24.4 7.3 0.3 (3.4 ) (3.1 ) Foreign exchange translation 5.9 0.4 6.3 (5.8 ) (0.6 ) (6.4 ) Balance, end of year $ (85.2 ) $ 0.1 $ (85.1 ) $ (148.5 ) $ (14.7 ) $ (163.2 )
Realized and Unrealized Losses Recorded To Income For Level 3 Measurements	Realized and Unrealized Gains (Losses) Recorded to Income for Level 3 Measurements Year Ended December 31 2019 2018 Recorded to revenue $ 75.2 $ (11.1 ) Recorded to cost of sales (26.2 ) (3.7 ) $ 49.0 $ (14.8 )
Summary of Unrealized Gains (Losses) on Risk Management Contracts	Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income (Loss) Year Ended December 31 2019 2018 Natural gas $ 22.5 $ (2.2 ) Energy exports (86.7 ) — NGL frac spread (17.4 ) 40.0 Power (4.9 ) 9.3 Foreign exchange 1.2 33.7 $ (85.3 ) $ 80.8
Schedule of Offsetting Assets and Liabilities	The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if specific credit-risk-related contingent features underlying these agreements were triggered: As at December 31, December 31, Risk management liabilities with credit-risk-contingent features $ 42.2 $ 14.7 Maximum potential collateral requirements $ 29.0 $ 7.5 As at December 31, 2019 Risk management assets (a) Gross amounts of recognized Gross amounts Netting Net amounts Natural gas $ 121.2 $ (53.7 ) $ — $ 67.5 Energy exports 9.7 (2.7 ) 4.4 11.4 NGL frac spread 0.3 (0.2 ) — 0.1 Power 53.5 (6.8 ) — 46.7 $ 184.7 $ (63.4 ) $ 4.4 $ 125.7 Risk management liabilities (b) Natural gas $ 226.1 $ (53.7 ) $ (27.7 ) $ 144.7 Energy exports 89.5 (2.7 ) — 86.8 NGL frac spread 1.7 (0.2 ) — 1.5 Power 68.7 (6.8 ) (3.1 ) 58.8 $ 386.0 $ (63.4 ) $ (30.8 ) $ 291.8 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $86.6 million and risk management assets (non‑current) balance of $39.1 million . (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $124.8 million and risk management liabilities (non‑current) balance of $167.0 million . As at December 31, 2018 Risk management assets (a) Gross amounts of Gross amounts Netting Net amounts Natural gas $ 200.8 $ (82.0 ) $ — $ 118.8 NGL frac spread 18.7 (0.7 ) — 18.0 Power 42.8 (7.8 ) — 35.0 $ 262.3 $ (90.5 ) $ — $ 171.8 Risk management liabilities (b) Natural gas $ 340.4 $ (82.0 ) $ (3.3 ) $ 255.1 NGL frac spread 2.7 (0.7 ) — 2.0 Power 50.6 (7.8 ) 1.2 44.0 Foreign exchange 1.2 — — 1.2 $ 394.9 $ (90.5 ) $ (2.1 ) $ 302.3 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $114.1 million and risk management assets (non‑current) balance of $57.7 million . (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $89.3 million and risk management liabilities (non‑current) balance of $213.0 million . Cash Collateral The following table presents collateral not offset against risk management assets and liabilities: As at December 31, December 31, Collateral posted with counterparties $ 29.1 $ 27.6 Cash collateral held representing an obligation $ 0.3 $ 0.8
Schedule of Notional Amounts of Outstanding Derivative Positions	AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2019 and 2018 : December 31, 2019 Fixed price Period Notional volume (MWh) Fair Value Power sales 31.63 to 66.76 1-42 8,034,024 $ 39.0 Power purchases 31.63 to 66.76 1-60 8,552,467 $ (27.3 ) Swap purchases (7.88) to 74.26 1-48 25,058,577 $ (23.8 ) December 31, 2018 Fixed price Period Notional volume (MWh) Fair Value Power sales 26.90 to 95.03 1-60 11,881,575 $ (1.9 ) Power purchases 25.50 to 50.25 1-42 8,507,874 $ 16.4 Swap purchases (6.07) to 76.18 1-48 20,957,180 $ (22.3 ) AltaGas had the following contracts outstanding as at December 31, 2019 : December 31, 2019 Fixed price Period Notional volume (Bbl) Fair Value Propane 21.49 to 29.71 1-27 9,374,826 $ (75.4 ) AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2019 and 2018 : December 31, 2019 Fixed price Period (months) Notional volume Fair Value Butane swaps 73.02 to 75.15/Bbl 1-12 346,852 Bbl $ (0.5 ) Crude oil swaps 73.02 to 75.15/Bbl 1-12 212,587 Bbl $ (0.9 ) Natural gas swaps 1.58 to 1.86/GJ 1-12 3,883,992 GJ $ — December 31, 2018 Fixed price Period Notional volume Fair Value Propane swaps $38.89 to $47.63/Bbl 1-12 1,725,114 Bbl $ 12.6 Butane swaps $52.95 to $55.26/Bbl 1-12 74,371 Bbl $ 1.2 Crude oil swaps $79.64 to $86.28/Bbl 1-12 329,230 Bbl $ 6.0 Natural gas swaps $1.38 to $1.68/GJ 1-12 9,490,365 GJ $ (3.8 ) AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2019 and 2018 : December 31, 2019 Fixed price (per GJ) Period Notional volume (GJ) Fair Value Sales 1.32 to 6.81 1-166 698,126,985 $ 28.9 Purchases 0.22 to 6.81 1-167 1,406,991,689 $ (104.4 ) Swaps 0.22 to 10.24 1-51 541,652,374 $ (1.7 ) December 31, 2018 Fixed price Period Notional volume (GJ) Fair Value Sales 1.07 to 12.19 1-178 858,640,810 $ 19.0 Purchases 0.69 to 16.26 1-179 1,638,207,391 $ (179.5 ) Swaps 2.56 to 15.37 1-231 621,578,572 $ 20.9
Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives	The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2019 : Factor Increase or decrease to forward prices Increase or decrease to income before tax ($ millions) Alberta power price $1/MWh 2.3 PJM power price US$1/MWh 1.9 AECO natural gas price $0.50/GJ 1.1 NYMEX natural gas price US$0.50/GJ 2.6 Energy Exports: Propane Far East Index to Mont Belvieu spread $1/Bbl 3.4 Baltic LPG Freight $1/Bbl 6.1 NGL frac spread: Western Texas Intermediate (WTI) crude oil $1/Bbl 0.6 Natural gas $0.50/GJ 1.9
Schedule of Accounts Receivable Past Due or Impaired	AltaGas had the following past due or impaired accounts receivable (AR): As at December 31, 2019 Total AR accruals Receivables impaired Less than 30 days 31 to 60 days 61 to 90 days Over 90 days Trade receivable $ 1,238.2 $ 343.5 $ 33.2 $ 757.9 $ 61.2 $ 11.6 $ 30.8 Other 17.4 — — 17.3 — — 0.1 Allowance for credit losses (33.2 ) — (33.2 ) — — — — $ 1,222.4 $ 343.5 $ — $ 775.2 $ 61.2 $ 11.6 $ 30.9 As at December 31, 2018 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 1,574.6 $ 447.5 $ 54.7 $ 961.5 $ 74.1 $ 12.8 $ 24.0 Other 27.6 — — 27.5 — — 0.1 Allowance for credit losses (54.7 ) — (54.7 ) — — — — $ 1,547.5 $ 447.5 $ — $ 989.0 $ 74.1 $ 12.8 $ 24.1 Allowance for credit losses December 31, 2019 December 31, 2018 Balance, beginning of year $ 54.7 $ 2.4 Foreign exchange translation (2.6 ) 0.1 New allowance (a) 27.5 53.1 Change in allowance (b) (9.2 ) (0.9 ) Allowance applied to uncollectible customer accounts (37.2 ) — Balance, end of year $ 33.2 $ 54.7 (a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s allowance for credit losses of approximately $52.9 million . (b) Includes removal of allowance related to asset disposals of approximately $8.1 million in 2019.
Schedule of Contractual Maturities for Financial Liabilities	AltaGas had the following contractual maturities with respect to financial liabilities: Contractual maturities by period As at December 31, 2019 Total Less than 1 year 1-3 years 4-5 years After 5 years Accounts payable and accrued liabilities $ 1,324.9 $ 1,324.9 $ — $ — $ — Dividends payable 22.3 22.3 — — — Short-term debt 460.0 460.0 — — — Other current liabilities (a) 15.4 15.4 — — — Risk management contract liabilities 291.8 124.8 34.1 13.2 119.7 Current portion of long-term debt (b) 920.4 920.4 — — — Long-term debt (b) 5,872.5 — 1,489.2 921.3 3,462.0 $ 8,907.3 $ 2,867.8 $ 1,523.3 $ 934.5 $ 3,581.7 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition. Contractual maturities by period As at December 31, 2018 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,488.2 $ 1,488.2 $ — $ — $ — Dividends payable 22.0 22.0 — — — Short-term debt 1,209.9 1,209.9 — — — Other current liabilities (a) 11.2 11.2 — — — Other long-term liabilities (a) 2.0 — 2.0 — — Risk management contract liabilities 302.3 89.3 113.3 33.3 66.4 Current portion of long-term debt (b) 888.5 888.5 — — — Long-term debt (b) 8,014.8 — 3,063.4 1,592.6 3,358.8 $ 11,938.9 $ 3,709.1 $ 3,178.7 $ 1,625.9 $ 3,425.2 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue by Major Sources	The following tables disaggregate revenue by major sources for the year: Year Ended December 31, 2019 Utilities Midstream Power Corporate Total Revenue from contracts with customers Commodity sales contracts $ — $ 1,093.7 $ 1,131.4 $ — $ 2,225.1 Midstream service contracts — 145.0 — — 145.0 Gas sales and transportation services 2,501.4 — — — 2,501.4 Storage services 28.1 — — — 28.1 Other 9.2 2.7 29.0 — 40.9 Total revenue from contracts with customers $ 2,538.7 $ 1,241.4 $ 1,160.4 $ — $ 4,940.5 Other sources of revenue Revenue from alternative revenue programs (a) $ 29.5 $ — $ — $ — $ 29.5 Leasing revenue (b) 0.9 136.6 105.1 — 242.6 Risk management and trading activities (c) (d) — 196.2 65.9 0.2 262.3 Other (4.9 ) 0.1 24.9 — 20.1 Total revenue from other sources $ 25.5 $ 332.9 $ 195.9 $ 0.2 $ 554.5 Total revenue $ 2,564.2 $ 1,574.3 $ 1,356.3 $ 0.2 $ 5,495.0 (a) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (b) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (c) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d). (d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2019 of $504.5 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018. Year Ended December 31, 2018 Utilities Midstream Power Corporate Total Revenue from contracts with customers Commodity sales contracts $ — $ 665.2 $ 497.5 $ — $ 1,162.7 Midstream service contracts — 205.0 — — 205.0 Gas sales and transportation services 1,684.3 — — — 1,684.3 Storage services 35.4 — — — 35.4 Other 10.7 0.6 25.1 — 36.4 Total revenue from contracts with customers $ 1,730.4 $ 870.8 $ 522.6 $ — $ 3,123.8 Other sources of revenue Revenue from alternative revenue programs (a) $ 21.7 $ — $ — $ — $ 21.7 Leasing revenue (b) 0.6 96.6 354.9 — 452.1 Risk management and trading activities (c) (d) 1.0 377.6 268.5 (2.9 ) 644.2 Other (1.1 ) (0.4 ) 16.0 0.4 14.9 Total revenue from other sources $ 22.2 $ 473.8 $ 639.4 $ (2.5 ) $ 1,132.9 Total revenue $ 1,752.6 $ 1,344.6 $ 1,162.0 $ (2.5 ) $ 4,256.7 (a) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (b) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (c) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. Revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d). (d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2018 of $264.2 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018.
Contract with Customer, Asset and Liability	Contract Assets As at December 31, December 31, Balance, beginning of year $ 58.8 $ — Additions 32.3 130.1 Transfers to held for sale (a) — (72.2 ) Transfers to accounts receivable (b) — (3.7 ) Foreign exchange translation (2.5 ) 4.6 Balance, end of year $ 88.6 $ 58.8 (a) In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset balance. Accordingly, the receivable was classified as held for sale at December 31, 2018. In February 2019, WGL Energy Systems completed the sale of the financing receivable (Note 4 ). (b) Amounts included in contract assets are transferred to accounts receivable when AltaGas’ right to consideration becomes unconditional. Contract Liabilities As at December 31, December 31, Balance, beginning of year $ 2.2 $ — Additions 1.9 2.6 Revenue recognized from contract liabilities (a) (2.2 ) (0.5 ) Foreign exchange translation (0.2 ) 0.1 Balance, end of year $ 1.7 $ 2.2 (a) Recognition of revenue related to performance obligations satisfied in the current period for amounts that were previously included in contract liabilities.
Schedule of Estimated Revenue Related to Performance Obligations	The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of December 31, 2019 : 2020 2021 2022 2023 2024 2025 & beyond Total Midstream service contracts $ 113.1 $ 89.8 $ 88.9 $ 86.5 $ 86.4 $ 971.9 $ 1,436.6 Storage services 24.2 24.2 23.5 23.2 23.2 168.4 286.7 Other 19.4 8.9 2.0 2.0 2.0 12.0 46.3 $ 156.7 $ 122.9 $ 114.4 $ 111.7 $ 111.6 $ 1,152.3 $ 1,769.6

Shareholders_ Equity (Tables)

Shareholders’ Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Schedule of Common Shares Issued and Outstanding	Common Shares Issued and Outstanding Number of Amount January 1, 2018 175,279,216 $ 4,007.9 Shares issued on conversion of subscription receipts, net of issuance costs 84,510,000 2,305.6 Shares issued for cash on exercise of options 57,275 1.3 Deferred taxes on share issuance cost — 13.3 Shares issued under DRIP 15,377,575 325.8 December 31, 2018 275,224,066 $ 6,653.9 Shares issued for cash on exercise of options 76,177 1.2 Deferred taxes on share issuance cost — (3.9 ) Shares issued under DRIP 3,774,442 67.8 Issued and outstanding at December 31, 2019 279,074,685 $ 6,719.0
Schedule of Preferred Shares Issued and Outstanding	As at December 31, 2019 December 31, 2018 Issued and Outstanding Number of shares Amount Number of shares Amount Series A 5,511,220 $ 137.8 5,511,220 $ 137.8 Series B 2,488,780 62.2 2,488,780 62.2 Series C 8,000,000 205.6 8,000,000 205.6 Series E 8,000,000 200.0 8,000,000 200.0 Series G 6,885,823 172.1 8,000,000 200.0 Series H 1,114,177 27.9 — — Series I 8,000,000 200.0 8,000,000 200.0 Series K 12,000,000 300.0 12,000,000 300.0 Washington Gas $4.80 series — — 150,000 19.7 $4.25 series — — 70,600 9.4 $5.00 series — — 60,000 7.9 Share issuance costs, net of taxes (28.5 ) (27.9 ) Fair value adjustment on WGL Acquisition (note 3) — 4.1 52,000,000 $ 1,277.1 52,280,600 $ 1,318.8
Summary of Cumulative Redeemable Preferred Shares	The following table outlines the characteristics of the cumulative redeemable preferred shares (a) : Current yield Annual dividend per share (b) Redemption price per share Redemption and conversion option date (c)(d) Right to convert into (d) Series A (e) 3.380 % $0.84500 $25 September 30, 2020 Series B Series B (f) (g) Floating Floating $25 September 30, 2020 Series A Series C (h) 5.290 % US$1.32250 US$25 September 30, 2022 Series D Series E (e) 5.393 % $1.34825 $25 December 31, 2023 Series F Series G (e) 4.620 % $1.15575 $25 September 30, 2024 Series H Series H (f) (g) Floating Floating $25 September 30, 2024 Series G Series I (i) 5.250 % $1.31250 $25 December 31, 2020 Series J Series K (j) 5.000 % $1.25000 $25 March 31, 2022 Series L (a) This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares, Series F Shares, and Series J Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, Series J Shares, and Series L Shares are also redeemable for $25.50 , and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption. (b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares, and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares and Series H Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series J Shares, and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. (c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. (d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter. (e) Holders of Series A Shares, Series E Shares, and Series G Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares). (f) Holders of Series B Shares and Series H Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent (Series B Shares) and 3.06 percent (Series H Shares). Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2019, the floating quarterly dividend rate is $0.26803 per share for Series B Shares and $0.29289 per share for Series H Shares for the period starting December 31, 2019 to, but excluding, March 31, 2020. (g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. Series H Shares can be redeemed for $25.50 per share on any date after September 30, 2019 that is not a Series H conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. (h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent . (i) Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent , provided that, in any event, such rate shall not be less than 5.25 percent per annum. (j) Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent , provided that, in any event, such rate shall not be less than 5.00 percent per annum.
Summary of Share Option Activity	The following table summarizes information about the Corporation’s share options: December 31, 2019 December 31, 2018 As at Options outstanding Options outstanding Number of Exercise price (a) Number of Exercise price (a) Share options outstanding, beginning of year 6,309,183 $ 25.18 4,533,761 $ 32.35 Granted 2,287,385 19.12 2,811,460 16.69 Exercised (76,177 ) 14.52 (57,275 ) 20.68 Forfeited (1,165,435 ) 27.31 (878,013 ) 36.47 Expired (311,000 ) 36.16 (100,750 ) 14.60 Share options outstanding, end of year 7,043,956 $ 22.49 6,309,183 $ 25.18 Share options exercisable, end of year 2,921,642 $ 27.70 2,897,723 $ 32.01 (a) Weighted average.
Summary of Employee Share Option Plan	The following table summarizes the employee share option plan as at December 31, 2019 : Options outstanding Options exercisable Number outstanding Weighted average exercise price Weighted average remaining contractual life Number exercisable Weighted average exercise price Weighted average remaining contractual life $14.52 to $18.00 2,557,328 $ 15.19 4.98 638,385 $ 14.62 4.79 $18.01 to $25.08 1,961,805 19.78 4.77 305,750 21.05 0.96 $25.09 to $46.70 2,524,823 32.00 2.72 1,977,507 32.95 2.39 7,043,956 $ 22.49 4.11 2,921,642 $ 27.70 2.77
Summary of Fair Value of Options Granted	The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows: Year ended December 31 2019 2018 Fair value per options ($) 2.30 1.27 Risk-free interest rate (%) 1.48 1.99 Expected life (years) 6 6 Expected volatility (%) 24.84 23.23 Annual dividend per share ($) (a) 0.96 1.18 Forfeiture rate (%) — — (a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as the grant dates.
Schedule of MTIP and DSUP Activity	PUs, RUs, and DSUs (number of units) 2019 2018 Balance, beginning of year 9,908,154 564,549 Acquired (a) — 5,291,621 Converted to cash (a) — (5,291,621 ) Granted 674,971 9,502,347 Exercised (113,668 ) — Vested and paid out (677,667 ) (148,154 ) Forfeited (3,377,962 ) (66,522 ) Units in lieu of dividends 71,003 55,934 Outstanding, end of year 6,484,831 9,908,154 (a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit. At December 31, 2019, the WGL PUs comprised approximately 4.9 million of the outstanding units (December 31, 2018 - 8.9 million ).

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Summary of Net Income per Common Share	The following table summarizes the computation of net income (loss) per common share: Year Ended December 31 2019 2018 Numerator: Net income (loss) applicable to controlling interests $ 833.5 $ (435.1 ) Less: Preferred share dividends (68.5 ) (66.6 ) Gain on redemption of preferred shares (note 25) 3.5 — Net income (loss) applicable to common shares $ 768.5 $ (501.7 ) Denominator: (millions) Weighted average number of common shares outstanding 276.9 222.6 Dilutive equity instruments (a) 0.5 — Weighted average number of common shares outstanding - diluted 277.4 222.6 Basic net income (loss) per common share $ 2.78 $ (2.25 ) Diluted net income (loss) per common share $ 2.77 $ (2.25 ) (a) Includes all options that have a strike price lower than the average share price of AltaGas' common shares during the periods noted.

Other Income (Tables)

Other Income (Tables)	12 Months Ended
	Dec. 31, 2019
Other Income and Expenses [Abstract]
Schedule of Other Income	Year Ended December 31 2019 2018 Gains (losses) from sale of assets $ 875.8 $ (10.6 ) Other components of net benefit cost (note 28) 27.4 18.9 Interest income and other revenue 9.0 2.7 Losses on investments (4.1 ) (10.1 ) $ 908.1 $ 0.9

Pension Plans and Retiree Ben_2

Pension Plans and Retiree Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Summary of Defined Benefit Plans	The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States: Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Projected benefit obligation (a) Balance, beginning of year $ 34.3 $ 1.9 $ 1,635.3 $ 458.0 $ 1,669.6 $ 459.9 Actuarial loss (gain) 2.1 0.2 182.0 (14.8 ) 184.1 (14.6 ) Current service cost 2.6 — 23.8 8.5 26.4 8.5 Member contributions — — — 2.2 — 2.2 Interest cost 1.2 0.1 67.8 19.1 69.0 19.2 Benefits paid (4.0 ) (0.1 ) (77.3 ) (24.4 ) (81.3 ) (24.5 ) Expenses paid (0.1 ) — (0.6 ) (0.1 ) (0.7 ) (0.1 ) Settlements — — (24.7 ) — (24.7 ) — Plan amendments — — 0.3 — 0.3 — Other — — — 1.0 — 1.0 Foreign exchange translation — — (82.0 ) (21.8 ) (82.0 ) (21.8 ) Balance, end of year $ 36.1 $ 2.1 $ 1,724.6 $ 427.7 $ 1,760.7 $ 429.8 Plan assets Fair value, beginning of year $ 13.8 $ — $ 1,354.1 $ 791.2 $ 1,367.9 $ 791.2 Actual return on plan assets 0.9 — 284.2 177.4 285.1 177.4 Employer contributions 4.3 0.1 38.7 0.1 43.0 0.2 Member contributions — — — 2.2 — 2.2 Benefits paid (4.0 ) (0.1 ) (77.3 ) (23.7 ) (81.3 ) (23.8 ) Expenses paid (0.1 ) — (0.6 ) (0.1 ) (0.7 ) (0.1 ) Settlements — — (25.7 ) — (25.7 ) — Other — — — 0.1 — 0.1 Foreign exchange translation — — (69.5 ) (41.3 ) (69.5 ) (41.3 ) Fair value, end of year $ 14.9 $ — $ 1,503.9 $ 905.9 $ 1,518.8 $ 905.9 Funded status $ (21.2 ) $ (2.1 ) $ (220.7 ) $ 478.2 $ (241.9 ) $ 476.1 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. Year Ended December 31, 2018 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Projected benefit obligation (a) Balance, beginning of year $ 165.6 $ 15.8 $ 303.8 $ 82.7 $ 469.4 $ 98.5 Plans disposed (132.1 ) (13.6 ) — — (132.1 ) (13.6 ) Actuarial gain (0.8 ) (0.1 ) (67.7 ) (33.8 ) (68.5 ) (33.9 ) Current service cost 2.4 0.1 16.2 5.3 18.6 5.4 Member contributions — — — 2.1 — 2.1 Interest cost 1.2 0.1 38.0 10.9 39.2 11.0 Benefits paid (2.7 ) — (43.2 ) (13.4 ) (45.9 ) (13.4 ) Expenses paid — — (0.9 ) (0.1 ) (0.9 ) (0.1 ) Plan combinations 0.7 — 1,311.7 382.9 1,312.4 382.9 Plan amendments — (0.4 ) — — — (0.4 ) Foreign exchange translation — — 77.4 21.4 77.4 21.4 Balance, end of year $ 34.3 $ 1.9 $ 1,635.3 $ 458.0 $ 1,669.6 $ 459.9 Plan assets Fair value, beginning of year $ 115.2 $ 8.1 $ 248.7 $ 70.8 $ 363.9 $ 78.9 Plans disposed (102.1 ) (8.1 ) — — (102.1 ) (8.1 ) Actual return on plan assets (0.3 ) — (54.7 ) (37.2 ) (55.0 ) (37.2 ) Employer contributions 3.4 — 7.6 2.5 11.0 2.5 Member contributions — — — 2.1 — 2.1 Benefits paid (2.7 ) — (43.2 ) (13.4 ) (45.9 ) (13.4 ) Expenses paid — — (0.9 ) (0.1 ) (0.9 ) (0.1 ) Plan combinations 0.3 — 1,133.2 732.7 1,133.5 732.7 Foreign exchange translation — — 63.4 33.8 63.4 33.8 Fair value, end of year $ 13.8 $ — $ 1,354.1 $ 791.2 $ 1,367.9 $ 791.2 Funded status $ (20.5 ) $ (1.9 ) $ (281.2 ) $ 333.2 $ (301.7 ) $ 331.3 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.
Schedule of Amounts Included in the Consolidated Balance Sheets	The following amounts were included in the Consolidated Balance Sheets: December 31, 2019 December 31, 2018 Defined Benefit Post- Retirement Benefits Total Defined Benefit Post- Retirement Benefits Total (a) Prepaid post-retirement benefits $ — $ 486.8 $ 486.8 $ — $ 341.4 $ 341.4 Accounts payable and accrued liabilities (25.7 ) — (25.7 ) (27.6 ) — (27.6 ) Future employee obligations (216.2 ) (10.7 ) (226.9 ) (274.1 ) (10.1 ) (284.2 ) $ (241.9 ) $ 476.1 $ 234.2 $ (301.7 ) $ 331.3 $ 29.6 (a) Account balances on the Consolidated Balance Sheets also include certain non-pension related amounts.
Schedule of Funded Status Based on Accumulated Benefit Obligation	The accumulated benefit obligation for all defined benefit plans were: As at December 31, 2019 December 31, 2018 Canada United States Canada United States Accumulated benefit obligation (a) $ 34.7 $ 1,616.4 $ 32.9 $ 1,525.6 (a) Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels.
Summary of Amounts Recorded in Other Comprehensive Income (Loss)	The following amounts were recorded in other comprehensive income (loss) and have not yet been recognized in net periodic benefit cost: Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit (cost) $ (0.2 ) $ 0.3 $ 0.1 $ — $ (0.1 ) $ 0.3 Net actuarial gain (loss) (9.4 ) (0.7 ) (14.9 ) 18.2 (24.3 ) 17.5 Recognized in AOCI pre-tax $ (9.6 ) $ (0.4 ) $ (14.8 ) $ 18.2 $ (24.4 ) $ 17.8 Increase (decrease) by the amount 2.3 0.1 7.0 (9.0 ) 9.3 (8.9 ) Net amount in AOCI after-tax $ (7.3 ) $ (0.3 ) $ (7.8 ) $ 9.2 $ (15.1 ) $ 8.9 Year Ended December 31, 2018 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit (cost) $ (0.3 ) $ 0.4 $ (0.2 ) $ — $ (0.5 ) $ 0.4 Net actuarial loss (8.7 ) (0.5 ) (10.7 ) (5.0 ) (19.4 ) (5.5 ) Recognized in AOCI pre-tax $ (9.0 ) $ (0.1 ) $ (10.9 ) $ (5.0 ) $ (19.9 ) $ (5.1 ) Increase by the amount 2.4 — 2.2 1.4 4.6 1.4 Net amount in AOCI after-tax $ (6.6 ) $ (0.1 ) $ (8.7 ) $ (3.6 ) $ (15.3 ) $ (3.7 )
Summary of Amounts Recorded in A Regulatory Asset (Liability)	The following amounts were recorded in a regulatory asset (liability) and have not yet been recognized in net periodic benefit cost: Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service cost (credit) $ — $ — $ 1.1 $ (105.4 ) $ 1.1 $ (105.4 ) Net actuarial loss (gain) — — 127.1 (155.8 ) 127.1 (155.8 ) Recognized in regulatory asset (liability) $ — $ — $ 128.2 $ (261.2 ) $ 128.2 $ (261.2 ) Year Ended December 31, 2018 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service cost (credit) $ — $ — $ 0.8 $ (110.2 ) $ 0.8 $ (110.2 ) Net actuarial loss (gain) — — 188.2 (52.6 ) 188.2 (52.6 ) Recognized in regulatory asset (liability) $ — $ — $ 189.0 $ (162.8 ) $ 189.0 $ (162.8 )
Schedule of Amounts to be Amortized from AOCI in the Next Fiscal Year	Amounts to be amortized in the next fiscal year from AOCI Defined Benefit Post-Retirement Benefits Past service cost (credit) $ 0.2 $ (0.7 ) Actuarial loss 4.0 0.3 Total $ 4.2 $ (0.4 )
Schedule of Amounts in Regulatory Assets (Liabilities) to be Recognized over Next Fiscal Year	Amounts to be amortized in the next fiscal year from regulatory assets (liabilities) Defined Benefit Post-Retirement Benefits Past service credit (cost) $ (0.2 ) $ 16.7 Actuarial gain (loss) (17.1 ) 0.5 Total $ (17.3 ) $ 17.2
Schedule of Net Periodic Benefit Expense	The net pension expense by plan was as follows: Year Ended December 31, 2019 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 2.6 $ — $ 23.8 $ 8.5 $ 26.4 $ 8.5 Interest cost (b) 1.2 0.1 67.8 19.1 69.0 19.2 Expected return on plan assets (b) (0.5 ) — (74.6 ) (37.1 ) (75.1 ) (37.1 ) Amortization of past service cost (credit) (b) 0.1 — 0.4 (21.9 ) 0.5 (21.9 ) Amortization of net actuarial loss (b) 0.9 — 11.7 0.1 12.6 0.1 Plan settlements (b) — — 4.1 — 4.1 — Other (b) — — — 0.9 — 0.9 Net benefit cost (income) recognized $ 4.3 $ 0.1 $ 33.2 $ (30.4 ) $ 37.5 $ (30.3 ) (a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss) . (b) Recorded under the line item “ other income ” on the Consolidated Statements of Income (Loss) . Year Ended December 31, 2018 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 2.4 $ 0.1 $ 16.2 $ 5.3 $ 18.6 $ 5.4 Interest cost (b) 1.2 0.1 38.0 10.9 39.2 11.0 Expected return on plan assets (b) (0.5 ) — (49.9 ) (21.6 ) (50.4 ) (21.6 ) Amortization of past service cost (credit) (b) 0.1 — 0.1 (11.5 ) 0.2 (11.5 ) Amortization of net actuarial loss (b) 0.6 — 7.7 0.4 8.3 0.4 Net benefit cost (income) recognized $ 3.8 $ 0.2 $ 12.1 $ (16.5 ) $ 15.9 $ (16.3 ) (a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss) . (b) Recorded under the line item “ other income ” on the Consolidated Statements of Income (Loss) .
Schedule of Collective Investment Mixes for Plan Assets	The collective investment mixes for the plans are as follows as at December 31, 2019 : Canada Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 1.9 $ 1.9 $ — 12.8 Canadian equities 4.1 4.1 — 27.5 Foreign equities 2.4 2.4 — 16.0 Fixed income 5.7 5.7 — 38.3 Real estate 0.8 — 0.8 5.4 $ 14.9 $ 14.1 $ 0.8 100.0 United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 10.8 $ 10.8 $ — 0.4 Canadian equities 2.6 2.6 — 0.1 Foreign equities (a) 302.5 302.2 0.3 12.6 Fixed income 933.0 123.2 809.8 38.7 Derivatives (0.2 ) — (0.2 ) — Other (b) 12.0 — 12.0 0.5 Total investments in the fair value hierarchy $ 1,260.7 $ 438.8 $ 821.9 52.3 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 648.9 26.9 Private equity/limited partnership (e) 55.6 2.3 Pooled separate accounts (f) 32.0 1.3 Collective trust fund (g) 433.8 18.1 Total fair value of plan investments $ 2,431.0 100.9 Net payable (h) (21.2 ) (0.9 ) $ 2,409.8 100.0 (a) Investments in foreign equities include U.S. and international securities. (b) As at December 31, 2019 , these investments consisted primarily of non-U.S. government bonds. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As at December 31, 2019 , investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans. (e) As at December 31, 2019 , investments in a private equity/limited partnership consisted of common stock of international companies. (f) As at December 31, 2019 , investments in pooled separate accounts consisted of income producing properties located in the United States. (g) As at December 31, 2019 , investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments. (h) As at December 31, 2019 , this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Total Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 12.7 $ 12.7 $ — 0.5 Canadian equities 6.7 6.7 — 0.3 Foreign equities (a) 304.9 304.6 0.3 12.6 Fixed income 938.7 128.9 809.8 38.7 Derivatives (0.2 ) — (0.2 ) — Real estate 0.8 — 0.8 — Other (b) 12.0 — 12.0 0.5 Total investments in the fair value hierarchy $ 1,275.6 $ 452.9 $ 822.7 52.6 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 648.9 26.8 Private equity/limited partnership (e) 55.6 2.3 Pooled separate accounts (f) 32.0 1.3 Collective trust fund (g) 433.8 17.9 Total fair value of plan investments $ 2,445.9 100.9 Net payable (h) (21.2 ) (0.9 ) $ 2,424.7 100.0 (a) Investments in foreign equities include U.S. and international securities. (b) As at December 31, 2019 , these investments consisted primarily of non-U.S. government bonds. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As at December 31, 2019 , investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans. (e) As at December 31, 2019 , investments in a private equity/limited partnership consisted of common stock of international companies. (f) As at December 31, 2019 , investments in pooled separate accounts consisted of income producing properties located in the United States. (g) As at December 31, 2019 , investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments. (h) As at December 31, 2019 , this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Year Ended December 31 2019 2018 Significant actuarial assumptions used in measuring net benefit plan costs Defined Post-Retirement Defined Post-Retirement Discount rate (%) 2.90 - 4.40 3.90 - 4.50 3.25 - 4.30 3.60 - 4.30 Expected long-term rate of return on plan assets (%) (a) 5.75 - 7.15 4.66 - 7.15 3.20 - 7.60 3.75 - 7.60 Rate of compensation increase (%) 2.75 - 4.10 4.10 2.75 - 4.10 4.10 Average remaining service life of active employees (years) 9.0 13.2 9.6 14.1 (a) Only applicable for funded plans
Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations	As at December 31 2019 2018 Significant actuarial assumptions used in measuring benefit obligations Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 2.90 - 3.50 3.10 - 3.60 3.60 - 4.40 3.90 - 4.50 Rate of compensation increase (%) 2.75 - 4.00 3.50 2.75 - 4.10 4.10
Summary of Assumed Health Care Cost Trend Rates	A one percentage point change in the assumed health care trend rates would have the following effects for 2019 : Increase Decrease Service and interest costs $ 1.9 $ (1.5 ) Accrued benefit obligation $ 22.7 $ (18.4 )
Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans	The following table shows the expected cash flows for defined benefit pension and other post-retirement plans: Defined Benefit Post-Retirement Benefits Expected employer contributions: 2020 $ 37.0 $ 3.2 Expected benefit payments: 2020 $ 104.6 $ 23.8 2021 $ 85.1 $ 22.6 2022 $ 93.3 $ 22.5 2023 $ 90.0 $ 22.3 2024 $ 90.7 $ 22.1 2025 - 2028 $ 474.1 $ 112.6

Commitments, Guarantees, and _2

Commitments, Guarantees, and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Summary of Future Payment Commitments	Future payments of these commitments as at December 31, 2019 are estimated as follows: 2020 2021 2022 2023 2024 2025 & beyond Total Gas purchase (a) $ 2,374.0 $ 2,488.2 $ 2,323.6 $ 2,076.1 $ 1,959.5 $ 22,772.0 $ 33,993.4 Propane purchase (b) 220.2 127.2 94.9 86.5 58.4 127.1 714.3 Electricity purchase (c) 567.2 318.1 160.0 56.4 11.0 0.4 1,113.1 Service agreements (d) (e) (f) 58.7 44.0 28.2 23.4 22.9 309.1 486.3 Pipeline and storage services (g) 721.2 652.5 627.8 600.4 550.5 3,876.7 7,029.1 Capital projects (h) 6.9 — — — — — 6.9 Operating leases (i) 27.8 27.1 26.5 24.5 20.1 100.1 226.1 Environmental (j) 6.5 4.3 1.0 1.0 0.6 0.4 13.8 Merger commitments (k) 8.2 3.8 1.9 1.9 1.9 4.3 22.0 $ 3,990.7 $ 3,665.2 $ 3,263.9 $ 2,870.2 $ 2,624.9 $ 27,190.1 $ 43,605.0 (a) AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period. (b) AltaGas enters into contracts to purchase propane for its operations at RIPET. These contracts are used to ensure that there is an adequate supply of propane to meet shipment commitments and to minimize exposure to market price fluctuations. Propane purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period. (c) AltaGas enters into contracts to purchase electricity from various suppliers for its non-utility business. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include US $17.4 million of commitments related to renewable energy credits. (d) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hours per CT, or 25 years , whichever comes first. The LTSA has variable fees on a per equivalent operating hour basis. As at December 31, 2019 , the total commitment was $167.9 million payable over the next 16 years , of which $45.4 million is expected to be paid over the next five years. (e) In 2017, AltaGas entered into a 12 -year service agreement for tug services to support the marine operations of RIPET. (f) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI), provision of certain terminal services, and access to RTI's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and RTI executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement. (g) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044. (h) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs. (i) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, and office and other equipment. (j) Environmental commitments include committed payments related to certain environmental response costs. (k) Represents the estimated future payments of merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that will be expensed when costs are incurred in the future, including the investment of up to US$70 million over a ten year period to further extend natural gas service, investment of US$8 million for leak mitigation within three years of the merger, hiring damage prevention trainers in each jurisdiction for a total of US$2 million over five years, and developing 15 megawatts of either electric grid energy storage or Tier 1 renewable resources within five years. As at December 31, 2019, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$17 million .

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Summary of Related Party Amounts Included in Balance Sheets	Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows: As at December 31, 2019 December 31, 2018 Due from related parties Accounts receivable (a) $ 17.8 $ 60.8 Long-term investments and other assets (b) 45.0 45.0 $ 62.8 $ 105.8 Due to related parties Accounts payable (c) $ 2.7 $ 6.3 Risk management liabilities - current (d) — 0.9 $ 2.7 $ 7.2 (a) Receivables from joint ventures and ACI. (b) AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021. As at December 31, 2019 , Petrogas had drawn $45.0 million ( December 31, 2018 - $45.0 million ) under the facility. (c) Payables to joint venture. (d) Foreign exchange hedge with ACI.
Schedule of Related Party Transactions	The following transactions with related parties have been recorded on the Consolidated Statements of Income (Loss) for the years ended December 31, 2019 and 2018 : Year Ended December 31 2019 2018 Revenue (a) $ 114.9 $ 68.4 Cost of sales (b) $ 12.8 $ 4.2 Operating and administrative recoveries (c) $ (1.8 ) $ (1.3 ) Other income (d) $ 3.2 $ 9.2 (a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI. For the year ended December 31, 2018, revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million . (b) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates. (c) Administrative costs recovered from joint ventures. In addition, subsequent to the initial public offering (IPO) of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. (d) Interest income from loans to Petrogas (secured loan facility) and loans to ACI. Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of 2018. Loans to ACI were fully repaid by December 31, 2018.

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Schedule of Changes in Operating Assets and Liabilities	The following table details the changes in operating assets and liabilities from operating activities: Year Ended 2019 2018 Source (use) of cash: Accounts receivable $ 168.4 $ (526.9 ) Inventory (2.1 ) (100.8 ) Other current assets (85.5 ) 12.5 Regulatory assets - current 7.1 (15.8 ) Accounts payable and accrued liabilities (280.2 ) 237.9 Customer deposits (16.9 ) (13.3 ) Regulatory liabilities - current 34.2 69.2 Risk management liabilities - current 1.1 — Other current liabilities (5.6 ) (5.9 ) Other operating assets and liabilities (52.0 ) (143.4 ) Changes in operating assets and liabilities $ (231.5 ) $ (486.5 )
Schedule of Supplemental Cash Payments	The following cash payments have been included in the determination of earnings: Year Ended 2019 2018 Interest paid (net of capitalized interest) $ 351.7 $ 288.9 Income taxes paid $ 67.2 $ 36.9
Reconciliation of Cash and Restricted Cash Balances	he following table is a reconciliation of cash and restricted cash balances: As at December 31 2019 2018 Cash and cash equivalents $ 57.1 $ 101.6 Restricted cash holdings from customers - current 4.0 4.1 Restricted cash holdings from customers - non-current 3.9 6.1 Restricted cash included in prepaid expenses and other current assets (a) 25.4 27.6 Restricted cash included in long-term investments and other assets (a) 32.0 61.7 Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows $ 122.4 $ 201.1 (a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relate to Rabbi trusts associated with WGL’s pension plans (see Note 28 ).

Segmented Information (Tables)

Segmented Information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Reconciliation Of Segment Revenue	The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 24 : Year Ended December 31, 2019 Utilities Midstream Power Corporate Total External revenue (note 24) $ 2,564.2 $ 1,574.3 $ 1,356.3 $ 0.2 $ 5,495.0 Intersegment revenue 26.6 6.9 10.9 — $ 44.4 Segment revenue $ 2,590.8 $ 1,581.2 $ 1,367.2 $ 0.2 $ 5,539.4 Year Ended December 31, 2018 Utilities Midstream Power Corporate Total External revenue (note 24) $ 1,752.6 $ 1,344.6 $ 1,162.0 $ (2.5 ) $ 4,256.7 Intersegment revenue 13.0 90.4 9.0 0.1 112.5 Segment revenue $ 1,765.6 $ 1,435.0 $ 1,171.0 $ (2.4 ) $ 4,369.2
Schedule of Geographic Information	Geographic Information Year Ended December 31 2019 2018 Revenue (a) Canada $ 1,244.8 $ 1,626.8 United States 4,325.5 2,553.0 TOTAL $ 5,570.3 $ 4,179.8 (a) Operating revenue from external customers, excluding unrealized gains (losses) or risk management contracts. As at December 31 2019 2018 Property, plant and equipment Canada $ 2,682.2 $ 2,348.2 United States 7,443.3 8,581.4 TOTAL $ 10,125.5 $ 10,929.6
Schedule of Segment Composition	The following tables show the composition by segment: Year Ended December 31, 2019 Utilities Midstream Power Corporate Intersegment Elimination (a) Total Segment revenue $ 2,590.8 $ 1,581.2 $ 1,367.2 $ 0.2 $ (44.4 ) $ 5,495.0 Cost of sales (1,117.9 ) (1,057.7 ) (1,084.4 ) — 32.9 (3,227.1 ) Operating and administrative (860.7 ) (249.1 ) (159.8 ) (40.6 ) 11.5 (1,298.7 ) Accretion expenses (0.1 ) (3.9 ) (1.1 ) — — (5.1 ) Depreciation and amortization (261.6 ) (92.1 ) (72.3 ) (12.0 ) — (438.0 ) Provisions on assets (note 6) — (35.2 ) (380.6 ) — — (415.8 ) Income from equity investments 18.3 122.4 0.4 — — 141.1 Other income (loss) 27.0 28.7 853.8 (1.4 ) — 908.1 Foreign exchange gains (losses) — (4.5 ) — 3.5 — (1.0 ) Interest expense — — — (345.8 ) — (345.8 ) Income (loss) before income taxes $ 395.8 $ 289.8 $ 523.2 $ (396.1 ) $ — $ 812.7 Net additions (reductions) to: Property, plant and equipment (b) $ 839.6 $ 350.3 $ (2,281.3 ) $ 1.2 $ — $ (1,090.2 ) Intangible assets $ 22.6 $ 4.9 $ — $ 9.0 $ — $ 36.5 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets. Year Ended December 31, 2018 Utilities Midstream Power Corporate Intersegment Elimination (a) Total Segment revenue $ 1,765.6 $ 1,435.0 $ 1,171.0 $ (2.4 ) $ (112.5 ) $ 4,256.7 Cost of sales (838.3 ) (976.4 ) (743.7 ) — 103.1 (2,455.3 ) Operating and administrative (727.4 ) (201.7 ) (159.1 ) (50.6 ) 9.8 (1,129.0 ) Accretion expenses (0.1 ) (4.0 ) (6.8 ) — — (10.9 ) Depreciation and amortization (165.8 ) (84.4 ) (130.5 ) (13.3 ) — (394.0 ) Provision on assets (note 6) (193.7 ) (153.7 ) (381.3 ) — — (728.7 ) Income (loss) from equity investments 7.2 51.1 (10.4 ) — — 47.9 Other income (loss) 4.5 0.7 (5.9 ) 2.0 (0.4 ) 0.9 Foreign exchange gains (losses) — (0.2 ) (0.1 ) 4.8 — 4.5 Interest expense (103.9 ) (10.6 ) (8.9 ) (185.6 ) — (309.0 ) Income (loss) before income taxes $ (251.9 ) $ 55.8 $ (275.7 ) $ (245.1 ) $ — $ (716.9 ) Net additions (reductions) to: Property, plant and equipment (b) $ 507.0 $ 383.4 $ (321.9 ) $ 4.0 $ — $ 572.5 Intangible assets $ 21.8 $ 4.7 $ 12.5 $ 6.7 $ — $ 45.7 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.
Schedule of Goodwill and Total Assets by Segment	The following table shows goodwill and total assets by segment: Utilities Midstream Power Corporate Total As at December 31, 2019 Goodwill $ 3,573.0 $ 246.5 $ 122.6 $ — $ 3,942.1 Segmented assets $ 13,097.1 $ 5,471.4 $ 1,019.9 $206.1 $ 19,794.5 As at December 31, 2018 Goodwill $ 3,450.8 $ 426.4 $ 191.0 $ — $ 4,068.2 Segmented assets $ 12,991.3 $ 6,398.8 $ 3,814.7 $ 282.9 $ 23,487.7

Organization and Overview of _2

Organization and Overview of the Business - Narratives (Details) customer in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2019USD ($)jurisdictionpipelinesegmentcustomerMW
Organization And Overview Of Business [Line Items]
Number of segments | segment	3
Utilities
Organization And Overview Of Business [Line Items]
Number of customers | customer	1.7
Utilities customers, base rate | $	$ 3.9
Number of regulated pipelines (pipelines)	2
Midstream
Organization And Overview Of Business [Line Items]
Number of regulated pipelines (pipelines)	2
Number of utilities jurisdictions | jurisdiction	5
Midstream | Ridley Island Propane Terminal
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	70.00%
Midstream | AltaGas Idemitsu Joint Venture LP
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	50.00%
Midstream | Petrogas Preferred Shares
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	33.33%
Power
Organization And Overview Of Business [Line Items]
Power capacity | MW	710

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Summary of Estimated Useful Lives of Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2019
Minimum
Property, Plant and Equipment
Useful life	2 years
Minimum | Corporate
Property, Plant and Equipment
Useful life	3 years
Minimum | Utilities
Property, Plant and Equipment
Useful life	4 years
Minimum | Power
Property, Plant and Equipment
Useful life	3 years
Maximum | Corporate
Property, Plant and Equipment
Useful life	7 years
Maximum | Utilities
Property, Plant and Equipment
Useful life	69 years
Maximum | Midstream
Property, Plant and Equipment
Useful life	45 years
Maximum | Power
Property, Plant and Equipment
Useful life	46 years

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Summary of Estimated Useful Lives of Finite-Lived Intangible Assets (Details)	12 Months Ended
	Dec. 31, 2019
WGL Holdings
Finite-Lived Intangible Assets
Intangible asset, useful life	20 years
Energy services relationships | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Energy services relationships | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	19 years
Electricity service agreements | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	2 years
Electricity service agreements | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	60 years
Software | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	3 years
Software | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	10 years
Land rights | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Land rights | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	64 years
Franchises and consents | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	9 years
Franchises and consents | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	25 years
E&T contracts
Finite-Lived Intangible Assets
Intangible asset, useful life	25 years
Commodity contracts | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Commodity contracts | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	20 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Share Options and Other Compensation Plans (Details)	12 Months Ended
	Dec. 31, 2019multiple$ / shares
Share-based Compensation Arrangement by Share-based Payment Award
Other portions of RU's and PSU's (per share) | $ / shares	$ 1
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Performance multiplier	0
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Performance multiplier	2.4

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Pension Plan and Post Retirement Benefits (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit
Defined Benefit Plan Disclosure
Average remaining service life of active employees	9 years	9 years 7 months 6 days
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Average remaining service life of active employees	13 years 2 months	14 years 1 month 6 days

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Effects of Adoption of New Accounting Principles (Details) - CAD ($) $ in Millions	Jan. 01, 2020	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle\
Current liabilities		$ 3,125.1		$ 4,102
ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle\
Long term assets			$ 181
Long term liabilities			170.5
Current liabilities			$ 23.3
ASU 2016-13 | Accounts receivable | Subsequent Event | Forecast
New Accounting Pronouncements or Change in Accounting Principle\
Anticipated effect on account balance (percent)	(1.00%)
ASU 2016-13 | Accumulated deficit | Subsequent Event | Forecast
New Accounting Pronouncements or Change in Accounting Principle\
Anticipated effect on account balance (percent)	1.00%

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Collaborative Agreements (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Income (loss) from collaborative agreements	$ 1.4	$ (0.2)

Acquisition of WGL Holdings, _3

Acquisition of WGL Holdings, Inc. - Narratives (Details) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2019CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Jul. 06, 2018$ / $
Business Acquisition
Currency exchange rate (usd/cad) | $ / $				1.31
Adjustment to goodwill on business acquisition		$ 92.2	$ 0
WGL Holdings
Business Acquisition
Adjustment to goodwill on business acquisition	$ 92.2

Acquisition of WGL Holdings, _4

Acquisition of WGL Holdings, Inc. - Schedule of Final Purchase Price Allocation (Details) - CAD ($) $ in Millions	Jul. 06, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair value assigned to net assets
Goodwill (note 11)		$ 3,942.1	$ 4,068.2	$ 817.3
WGL Holdings
Business Acquisition
Purchase consideration	$ 5,973
Fair value assigned to net assets
Current assets	1,220
Property, plant and equipment	5,884
Intangible assets	577
Regulatory assets	408
Long-term investments	1,475
Other long-term assets	462
Current liabilities	(1,916)
Long-term debt	(2,548)
Preferred shares	(41)
Regulatory liabilities	(1,126)
Deferred income taxes	(741)
Other long-term liabilities	(959)
Non-controlling interest	(9)
Accumulated other comprehensive income	(2)
Fair value of net assets acquired	2,684
Goodwill (note 11)	$ 3,289

Dispositions (Details)

Dispositions (Details) $ in Millions

Nov. 13, 2019USD ($)

Nov. 13, 2019CAD ($)

Sep. 26, 2019USD ($)

Sep. 26, 2019CAD ($)

Aug. 13, 2019USD ($)

Aug. 13, 2019CAD ($)

May 31, 2019USD ($)

May 31, 2019CAD ($)

Feb. 01, 2019CAD ($)

Jan. 31, 2019CAD ($)

Feb. 28, 2019CAD ($)

Sep. 30, 2019USD ($)

Sep. 30, 2019CAD ($)

Dec. 31, 2019CAD ($)

Dec. 31, 2018CAD ($)

Dec. 31, 2019USD ($)

Dec. 31, 2019CAD ($)

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Gains (losses) from sale of assets

$ 875,800,000

$ (10,600,000)

Proceeds from disposition of financing receivable

73,500,000

0

Meade Pipeline Co. LLC (Meade)

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Provision on equity method investments

44,200,000

Disposal by sale

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Proceeds from disposition of financing receivable

$ 73,500,000

Loss on sales of receivables

1,300,000

Disposal by sale | Northwest Hydro

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Ownership percentage (percent)

55.00%

Proceeds from disposition

$ 1,300,000,000

Gain (loss) on disposal

687,600,000

Disposal by sale | Non-Core Midstream and Power

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Proceeds from asset dispositions

$ 87,800,000

Gains (losses) from sale of assets

(1,200,000)

Disposal by sale | Stonewall Gas Gathering System

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Proceeds from disposition

$ 280

$ 379,200,000

Gain (loss) on disposal

34,100,000

Disposal by sale | Craven County Wood Energy LP and Grayling Generation Station LP

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Proceeds from disposition

$ 18.5

$ 24,500,000

Gain (loss) on disposal

$ 0

Disposal by sale | US Portfolio

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Proceeds from asset dispositions

$ 735

$ 975,000,000

Gains (losses) from sale of assets

167,500,000

Disposal by sale | Meade

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Proceeds from disposition

$ 610.8

$ 811,500,000

Gains (losses) from sale of assets

(11,100,000)

Held for sale

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Liabilities held for sale

$ 171,400,000

$ 3,800,000

Held for sale | US Portfolio

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Liabilities held for sale

$ 24.8

$ 32,200,000

Assets held for sale disposed of by sale | Capital Spare

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations

Proceeds from disposition

$ 3.5

$ 4,600,000

Gain (loss) on disposal

$ 0

Assets Held For Sale - Schedule

Assets Held For Sale - Schedule of Assets Held for Sale (Details) - Held for sale - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Assets held for sale
Cash	$ 0	$ 4.9
Accounts receivable	0	85.2
Inventory	0	0.5
Property, plant and equipment	22.9	1,189.6
Intangible assets	0	248.7
Operating right-of-use assets	0.4
Goodwill	1	0
Other long-term assets	3.2	0
Total assets held for sale	27.5	1,528.9
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	0	23.8
Asset retirement obligations	0.2	10.8
Unamortized investment tax credits	3.2	0
Disposal Group, Including Discontinued Operation, Operating Lease Liabilities, Non-current	0.4
Other long-term liabilities	0	136.8
Total liabilities associated with assets held for sale	$ 3.8	$ 171.4

Provisions on Assets - Schedule

Provisions on Assets - Schedule of Provisions on Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Provisions On Assets Disclosure
Provisions on assets	$ 415.8	$ 728.7
Utilities
Provisions On Assets Disclosure
Provisions on assets	0	193.7
Midstream
Provisions On Assets Disclosure
Provisions on assets	35.2	153.7
Power
Provisions On Assets Disclosure
Provisions on assets	$ 380.6	$ 381.3

Provisions on Assets - Narrativ

Provisions on Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Provisions On Assets Disclosure
Provisions on assets	$ 415.8	$ 728.7
Utilities
Provisions On Assets Disclosure
Provisions on assets	0	193.7
Midstream
Provisions On Assets Disclosure
Provisions on assets	35.2	153.7
Midstream | Property, Plant and Equipment
Provisions On Assets Disclosure
Provisions on assets	35
Midstream | Intangible Assets
Provisions On Assets Disclosure
Provisions on assets	0.2
Power
Provisions On Assets Disclosure
Provisions on assets	$ 380.6	$ 381.3

Inventory - Schedule of Invento

Inventory - Schedule of Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Inventory
Natural gas held in storage	$ 359	$ 418
Materials and supplies	56.3	53.3
Renewable energy credits and emission compliance instruments	64.1	38.2
Natural gas liquids	26.2	6.4
Total inventory	505.6	515.9
Rate Regulated Utilities
Inventory
Natural gas held in storage	$ 214.3	$ 270.4

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment
Cost	$ 11,499.1	$ 11,952.7
Accumulated amortization	(1,373.6)	(1,023.1)
Net book value	10,125.5	10,929.6
Held for sale
Property, Plant and Equipment
Cost	25.2	2,999.3
Accumulated amortization	(2.3)	(1,809.7)
Net book value	22.9	1,189.6
Utilities
Property, Plant and Equipment
Cost	7,316.1	7,090.5
Accumulated amortization	(155)	(89.7)
Net book value	7,161.1	7,000.8
Midstream
Property, Plant and Equipment
Cost	3,182	3,178.2
Accumulated amortization	(585.4)	(845.7)
Net book value	2,596.6	2,332.5
Power
Property, Plant and Equipment
Cost	976.7	4,633.9
Accumulated amortization	(594.6)	(1,858.3)
Net book value	382.1	2,775.6
Corporate
Property, Plant and Equipment
Cost	49.5	49.4
Accumulated amortization	(40.9)	(39.1)
Net book value	$ 8.6	$ 10.3

Property, Plant and Equipment_2

Property, Plant and Equipment - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Interest capitalized	$ 14.5	$ 12.6
Capital projects under construction	725.2	872.7
Depreciation expense	$ 357.8	$ 324.3

Intangible Assets - Summary of

Intangible Assets - Summary of Intangible Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets
Cost	$ 758.6	$ 841.4
Accumulated amortization	(173)	(129.5)
Net book value	585.6	711.9
Held for sale
Finite-Lived Intangible Assets
Cost	0	277.4
Accumulated amortization	0	(28.7)
Net book value	0	248.7
E&T contracts
Finite-Lived Intangible Assets
Cost	26.6	26.6
Accumulated amortization	(15.2)	(14.3)
Net book value	11.4	12.3
Electricity service agreements
Finite-Lived Intangible Assets
Cost	8.5	269.5
Accumulated amortization	(7.8)	(25.9)
Net book value	0.7	243.6
Energy services relationships
Finite-Lived Intangible Assets
Cost	91.6	176.1
Accumulated amortization	(27.4)	(33.8)
Net book value	64.2	142.3
Software
Finite-Lived Intangible Assets
Cost	303.7	293.9
Accumulated amortization	(101.2)	(77.7)
Net book value	202.5	216.2
Land rights
Finite-Lived Intangible Assets
Cost	1.1	1.4
Accumulated amortization	(0.1)	(0.2)
Net book value	1	1.2
Commodity contracts
Finite-Lived Intangible Assets
Cost	327.1	346.3
Accumulated amortization	(21.3)	(6.3)
Net book value	305.8	340
Franchises and consents
Finite-Lived Intangible Assets
Cost	0	5
Accumulated amortization	0	0
Net book value	$ 0	$ 5

Intangible Assets - Narratives

Intangible Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense	$ 80.2	$ 69.7
Assets excluded from asset base subject to amortization	$ 184.5	$ 196.4

Intangible Assets - Summary o_2

Intangible Assets - Summary of Estimated Amortization Expense of Intangible Assets (Details) $ in Millions	Dec. 31, 2019CAD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2020	$ 79.1
2021	70.6
2022	69.7
2023	62.3
2024	24.2
Thereafter	$ 95.2

Leases - Components of Lease Co

Leases - Components of Lease Cost (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Lease, Cost
Operating lease cost (includes variable lease payments)	$ 29.2
Amortization of right-of-use assets	3.4
Interest on lease liabilities	0.3
Total finance lease cost	3.7
Total lease cost	$ 32.9

Leases - Supplemental Cashflow

Leases - Supplemental Cashflow Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from finance leases	$ (0.3)
Operating cash flows from operating leases	(20.6)
Financing cash flows from finance leases	(3.7)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	50.4
Finance leases	$ 5.4

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Location (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Operating lease right-of-use assets
Long-term	$ 169.8
Included in assets held for sale (note 5)	0.4
Total operating lease right-of-use assets	170.2
Operating lease liabilities
Current	(27.3)
Long-term	(153.4)
Included in liabilities associated with assets held for sale (note 5)	(0.4)
Total operating lease liabilities	(181.1)
Finance Leases
Property and equipment, gross	13.2
Accumulated depreciation	(3.3)
Property and equipment, net	9.9
Current portion of long-term debt	(3.5)
Long-term debt	(6.4)
Total finance lease liabilities	$ (9.9)	$ (0.8)
Weighted average remaining lease term (years)
Operating leases	10 years 11 months
Finance leases	5 years 2 months
Weighted average discount rate (%)
Operating leases	3.51%
Finance leases (percent)	3.68%

Leases - Schedule of Future Lea

Leases - Schedule of Future Lease Liability for Operating and Finance Lease (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Operating Leases
2020	$ 27.8
2021	27.1
2022	26.5
2023	24.5
2024	20.1
Thereafter	100.1
Total lease payments	226.1
Less: imputed interest	(45)
Total	181.1
Finance Leases
2020	3.5
2021	2.9
2022	2
2023	1.1
2024	0.4
Thereafter	2
Total lease payments	11.9
Less: imputed interest	(2)
Total	$ 9.9	$ 0.8

Leases - Narratives (Details)

Leases - Narratives (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Operating Leased Assets
Operating leases that have yet to commence	$ 4.8
Operating leases that have yet to commence (term)	6 years
Property, plant and equipment	$ 10,125.5	$ 10,929.6
Assets leased to others
Operating Leased Assets
Property, plant and equipment	$ 500

Leases - Schedule of Operating

Leases - Schedule of Operating Lease Receivables (Details) $ in Millions	Dec. 31, 2019CAD ($)
Operating Leases
2020	$ 118.3
2021	115.4
2022	115.6
2023	115.9
2024	47.8
Thereafter	477.5
Total	$ 990.5

Goodwill - Schedule of Goodwill

Goodwill - Schedule of Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill
Balance, beginning of year	$ 4,068.2	$ 817.3
Provisions on assets	0	(124.2)
Business acquisition (note 3)	0	3,196.4
Adjustment to goodwill on business acquisition (note 3)	92.2	0
Goodwill included in dispositions (note 4)	(29.1)	0
Reclassified to assets held for sale (note 5)	(1)	0
Foreign exchange translation	(188.2)	178.7
Balance, end of year	$ 3,942.1	$ 4,068.2

Long-Term Investments and Oth_3

Long-Term Investments and Other Assets - Schedule of Long-Term and Other Investments (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Investments, All Other Investments [Abstract]
Investments in publicly-traded entities	$ 4.3	$ 8.4
Loan to affiliate	45	45
Deferred lease receivable	17.4	24.4
Debt issuance costs associated with credit facilities	6.2	7.9
Refundable deposits	8.9	16.2
Prepayment on long-term service agreements	80.6	82.5
Cash calls from joint venture partners	9.5	0
Contract asset (note 24)	30	11.5
Rabbi trust (notes 28 and 31)	32	61.7
Other long-term receivables (note 29)	33.1	0
Other	29.5	25.5
Long-term investments and other assets	$ 296.5	$ 283.1

Variable Interest Entities - Na

Variable Interest Entities - Narratives (Details)	Nov. 12, 2019	May 05, 2017
Meade Pipeline Co LLC
Variable Interest Entity
VIE ownership percentage	55.00%
Central Penn
Variable Interest Entity
VIE inderect ownership percentage	21.00%
Altagas LPG | RILE LP
Variable Interest Entity
VIE ownership percentage		70.00%
Vopak | RILE LP
Variable Interest Entity
VIE ownership percentage		30.00%

Variable Interest Entities - Sc

Variable Interest Entities - Schedule of VIE Amounts in Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Variable Interest Entity
Current assets	$ 2,196.2	$ 4,033
Property, plant and equipment	10,125.5	10,929.6
Long-term investments and other assets	296.5	283.1
Total operating lease right-of-use assets	170.2
Current liabilities	(3,125.1)	(4,102)
Asset retirement obligations	(368.4)	(510.5)
Other long-term liabilities	(101.8)	(122)
VIE
Variable Interest Entity
Current assets	6.4	1,383.5
Property, plant and equipment	371.1	619.2
Long-term investments and other assets	53.3	48
Total operating lease right-of-use assets	0.1	0
Current liabilities	(3.6)	(161.8)
Asset retirement obligations	(3.3)	(0.9)
Other long-term liabilities	(0.1)	(3)
Net assets	$ 423.9	$ 1,885

Investments Accounted for by _3

Investments Accounted for by the Equity Method - Schedule of Equity Method Investments (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments
Equity method investment	$ 1,461.6	$ 2,392.4
Income (loss) from equity investments	$ 141.1	47.9
Canada | AltaGas Canada Inc. (ACI) (a)
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	37.00%
Equity method investment	$ 163.9	112.5
Income (loss) from equity investments	17	5.4
Equity method investment fair value	$ 367.9	$ 178.8
Shares owned (shares)	11,025,000	11,025,000
Share price (per share)	$ 33.37	$ 16.22
Canada | AltaGas Idemitsu Joint Venture LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 431.3	$ 342.9
Income (loss) from equity investments	$ 62.5	2.1
Canada | Inuvik Gas Ltd.
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	33.00%
Equity method investment	$ 0	0
Income (loss) from equity investments	$ 0	(0.2)
Canada | Sarnia Airport Storage Pool LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 18	18.7
Income (loss) from equity investments	1	1
Canada | Petrogas Preferred Shares
Schedule of Equity Method Investments
Equity method investment	150	150
Income (loss) from equity investments	$ 12.8	12.8
United States | Constitution Pipeline, LLC (Constitution)
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	10.00%
Equity method investment	$ 0.1	0
Income (loss) from equity investments	$ (0.5)	(0.2)
United States | Craven County Wood Energy LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 0	7.8
Income (loss) from equity investments	$ 0.1	(14.1)
United States | Eaton Rapids Gas Storage System
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 27	29.4
Income (loss) from equity investments	$ 1.3	2
United States | Grayling Generating Station LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 0	29
Income (loss) from equity investments	$ 0.3	3.6
United States | Meade Pipeline Co. LLC (Meade)
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	55.00%
Equity method investment	$ 0	757.8
Income (loss) from equity investments	$ (3.6)	12.2
United States | Mountain Valley Pipeline, LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	10.00%
Equity method investment	$ 671.3	532.5
Income (loss) from equity investments	$ 42.8	11.5
United States | Stonewall Gas Gathering System LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	30.00%
Equity method investment	$ 0	411.8
Income (loss) from equity investments	$ 7.4	$ 11.8

- Narratives (Details)

- Narratives (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Oct. 21, 2019$ / shares
Meade Pipeline Co. LLC (Meade)
Schedule of Equity Method Investments
Provision on equity method investments	$ 44.2
Craven County Wood Energy LP
Schedule of Equity Method Investments
Provision on equity method investments	$ 2.2	$ 14.5
AltaGas Canada Inc. | the Consortium
Schedule of Equity Method Investments
Equity Method Investment Proposed Share Acquisition Price | $ / shares			$ 33.50

Investments Accounted for by _4

Investments Accounted for by the Equity Method - Schedule of Combined Financial Information of Equity Method Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Revenues	$ 1,109.3	$ 351.6
Expenses	(355)	(142.7)
Gross profit	754.3	208.9
Current assets	411.1	1,204.6
Property, plant and equipment	8,033.8	7,602.5
Intangible assets	21.9	22.9
Long-term investments and other assets	1,458.8	1,326.6
Long-term investments and other assets	(393.8)	(1,015.2)
Other long-term liabilities	$ (992.1)	$ (949.6)

Short-term Debt - Schedule of S

Short-term Debt - Schedule of Short-Term Debt (Details) $ in Millions, $ in Millions	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
Debt Disclosure [Abstract]
Bank indebtedness		$ 0		$ 0.2
Commercial paper	$ 299.5	389	$ 839.5	1,145.2
Project financing		71		64.5
Short-term debt		$ 460		$ 1,209.9

Short-term Debt - Narrative (De

Short-term Debt - Narrative (Details)	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
Short-term Debt
Project financing		$ 71,000,000		$ 64,500,000
Commercial paper	$ 299,500,000	389,000,000	$ 839,500,000	1,145,200,000
Unsecured Extendible Revolving Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity		150,000,000		150,000,000
Debt instrument term (years)	4 years
Amount outstanding		25,500,000		117,000,000
Unsecured Bilateral Demand Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity	$ 200,000,000		200,000,000
Amount outstanding		156,400,000		147,300,000
Unsecured Extendible Revolving Facility II | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity	$ 300,000,000		$ 300,000,000
Amount outstanding		124,600,000		0
Parent Company | Unsecured Demand Revolving Operating Credit Facility
Short-term Debt
Credit facility maximum borrowing capacity		70,000,000		70,000,000
Amount outstanding		$ 0		$ 0

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-Term Debt (Details)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
Debt Instrument
Fair value adjustment on WGL Acquisition (note 3)		$ 84,300,000		$ 89,000,000
Finance lease liabilities (note 10)		9,900,000		800,000
Long-term debt including lease obligations		6,887,100,000		8,992,300,000
Less debt issuance costs		(36,400,000)		(35,200,000)
Total long-term debt		6,850,700,000		8,957,100,000
Less current portion		(922,900,000)		(890,200,000)
Long-term debt, noncurrent		5,927,800,000		8,066,900,000
$200 million Senior unsecured - 4.55 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		0		200,000,000
Debt face amount		$ 200,000,000
Debt instrument rate	4.55%	4.55%
$200 million Senior unsecured - 4.07 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 200,000,000		200,000,000
Debt face amount		$ 200,000,000
Debt instrument rate	4.07%	4.07%
$350 million Senior unsecured - 3.72 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 350,000,000		350,000,000
Debt face amount		$ 350,000,000
Debt instrument rate	3.72%	3.72%
$500 million Senior unsecured - 2.61 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 500,000,000		0
Debt face amount		$ 500,000,000
Debt instrument rate	2.61%	2.61%
$300 million Senior unsecured - 3.57 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 300,000,000		300,000,000
Debt face amount		$ 300,000,000
Debt instrument rate	3.57%	3.57%
$200 million Senior unsecured - 4.40 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 200,000,000		200,000,000
Debt face amount		$ 200,000,000
Debt instrument rate	4.40%	4.40%
$300 million Senior unsecured - 3.84 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 300,000,000		299,900,000
Debt face amount		$ 300,000,000
Debt instrument rate	3.84%	3.84%
$350 million Senior unsecured - 4.12 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 349,900,000		349,800,000
Debt face amount		$ 350,000,000
Debt instrument rate	4.12%	4.12%
$200 million Senior unsecured - 3.98 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 199,900,000		199,900,000
Debt face amount		$ 200,000,000
Debt instrument rate	3.98%	3.98%
$100 million Senior unsecured - 5.16 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 100,000,000		100,000,000
Debt face amount		$ 100,000,000
Debt instrument rate	5.16%	5.16%
$300 million Senior unsecured - 4.50 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 299,800,000		299,800,000
Debt face amount		$ 300,000,000
Debt instrument rate	4.50%	4.50%
$250 million Senior unsecured - 4.99 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 250,000,000		250,000,000
Debt face amount		$ 250,000,000
Debt instrument rate	4.99%	4.99%
US$450 million Senior unsecured - 2.25 to 4.76 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 0		$ 682,100,000
Debt face amount			$ 450,000,000
US$450 million Senior unsecured - 2.25 to 4.76 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate			2.25%	2.25%
US$450 million Senior unsecured - 2.25 to 4.76 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate			4.76%	4.76%
US$250 million Senior unsecured - 2.68 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 324,700,000		$ 341,100,000
Debt face amount	$ 250,000,000
Debt instrument rate	2.44%	2.44%
US$20 million Senior unsecured - 6.65 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 26,000,000		27,300,000
Debt face amount	$ 20,000,000
Debt instrument rate	6.65%	6.65%
US$40.5 million Senior unsecured - 5.44 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 52,600,000		55,300,000
Debt face amount	$ 40,500,000
Debt instrument rate	5.44%	5.44%
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 68,800,000		72,300,000
Debt face amount	$ 53,000,000
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	6.62%	6.62%
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	6.82%	6.82%
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 93,500,000		98,200,000
Debt face amount	$ 72,000,000
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	6.40%	6.40%
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	6.57%	6.57%
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 67,500,000		70,900,000
Debt face amount	$ 52,000,000
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	6.57%	6.57%
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	6.85%	6.85%
US$8.5 million Senior unsecured - 7.50 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 11,000,000		11,600,000
Debt face amount	$ 8,500,000
Debt instrument rate	7.50%	7.50%
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 64,900,000		68,200,000
Debt face amount	$ 50,000,000
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	5.70%	5.70%
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	5.78%	5.78%
US$75 million Senior unsecured - 5.21 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 97,400,000		102,300,000
Debt face amount	$ 75,000,000
Debt instrument rate	5.21%	5.21%
US$75 million Senior unsecured - 5.00 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 97,400,000		102,300,000
Debt face amount	$ 75,000,000
Debt instrument rate	5.00%	5.00%
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 389,600,000		409,300,000
Debt face amount	$ 300,000,000
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	4.22%	4.22%
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	4.60%	4.60%
US$450 million Senior unsecured - 3.80 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 584,500,000		613,900,000
Debt face amount	$ 450,000,000
Debt instrument rate	3.80%	3.80%
US$300 million Senior unsecured - 3.65 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 389,600,000		0
Debt face amount	$ 300,000,000
Debt instrument rate	3.65%	3.65%
US$300 million SEMCO Senior Secured - 5.15 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross		$ 389,600,000		409,300,000
Debt face amount	$ 300,000,000
Debt instrument rate	5.15%	5.15%
US$82 million SEMCO Senior Secured - 4.48 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross		$ 76,100,000		86,300,000
Debt face amount	$ 82,000,000
Debt instrument rate	4.48%	4.48%
Credit facilities | $1,400 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross		$ 89,600,000		964,700,000
Debt face amount		1,400,000,000
Credit facilities | US$300 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross		0		287,800,000
Debt face amount	$ 300,000,000
Credit facilities | Acquisition credit facility
Debt Instrument
Long-term debt, gross		0		113,200,000
Credit facilities | US$1,200 million revolving credit facility
Debt Instrument
Long-term debt, gross		0		1,637,000,000
Debt face amount				1,200,000,000
Credit facilities | US$300 million unsecured term facility
Debt Instrument
Long-term debt, gross		389,600,000		0
Debt face amount		300,000,000
Credit facilities | US$150 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross		163,500,000		0
Debt face amount		$ 150,000,000
Credit facilities | Commercial paper
Debt Instrument
Long-term debt, gross				$ 0

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)
Debt Instrument
Commercial paper	$ 283,500,000		$ 0
Revolving credit facility | Letter of Credit | WGL Holdings
Debt Instrument
Credit facility maximum borrowing capacity	250,000,000		650,000,000
Amount outstanding		$ 0
Revolving credit facility | Letter of Credit | Washington Gas
Debt Instrument
Credit facility maximum borrowing capacity	450,000,000		$ 350,000,000
Amount outstanding	$ 0

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis
Balance, beginning of year	$ 500.6	$ 88.3
Obligations acquired (note 3)	0	399.1
New obligations	7	3.3
Obligations settled	(2.5)	(4.2)
Disposals	(6.2)	(1.6)
Revision in estimated cash flow	(128.5)	3.8
Accretion expense	18.9	12.3
Foreign exchange translation	(20.7)	20.3
Reclassified to liabilities associated with assets held for sale (note 5)	(0.2)	(10.8)
Total	368.4	510.5
Less current portion (included in accounts payable and accrued liabilities)	(6.4)	(9.9)
Balance, end of year	$ 362	$ 500.6

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligations
Undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation	$ 727,000,000	$ 770,000,000
Legally restricted assets	$ 2,137
Minimum
Asset Retirement Obligations
Discount rate for asset retirement obligations (percent)	2.00%	1.50%
Maximum
Asset Retirement Obligations
Discount rate for asset retirement obligations (percent)	8.50%	8.50%

Environmental Matters (Details)

Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)site	Dec. 31, 2018CAD ($)
Site Contingency
Identified operated manufactured gas plants | site	12
Accrual for environmental loss contingencies	$ 13.8	$ 15.4
Regulatory assets	17.7	19.9
Maximum
Site Contingency
Accrual for environmental loss contingencies	$ 39.9	$ 40.1

Other Long-term Liabilities - S

Other Long-term Liabilities - Schedule of Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018
Other Long-Term Liabilities [Line Items]
Deferred lease payable		$ 0	$ 13.1
Deferred revenue		4	3.9
Customer advances for construction		63.9	58.6
Sundance B PPA's termination expense		0	2
Lease inducement			2.7
Merger commitments		14	21.4
Other long-term liabilities		19.9	20.3
Other long-term liabilities		$ 101.8	$ 122
ASTC
Other Long-Term Liabilities [Line Items]
Sundance B PPA's termination expense	$ 6
Settlement payment period	3 years
Accounts payable and accrued liabilities | ASTC
Other Long-Term Liabilities [Line Items]
Sundance B PPA's termination expense	$ 2

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income (loss) before income taxes - consolidated	$ 812.7	$ (716.9)
Statutory income tax rate (percent)	26.50%	27.00%
Expected taxes at statutory rates	$ 215.4	$ (193.6)
Permanent differences	10.9	(1)
Statutory and other rate differences	(51.6)	(19.6)
Rate adjustment for change in tax rates	(10.7)	1.3
Deferred income tax recovery on regulated assets	(24.8)	(7.3)
Tax differences on divestitures and transactions	(158.2)	(32.3)
Non-controlling interests	3.5	4.7
Change in valuation allowance	(11.1)	(22.3)
Other	(1)	6.9
Income tax expense, total	(27.6)	(263.2)
Current
Canada	26.7	23.7
United States	36.6	0.7
Current income tax provision	63.3	24.4
Deferred
Canada	11.6	(166.1)
United States	(102.5)	(121.5)
Deferred income tax expense	$ (90.9)	$ (287.6)
Effective income tax rate (percent)	(3.40%)	36.70%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Income Tax Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
PP&E and intangible assets	$ 1,450.6	$ 1,764.6
Regulatory assets	(204.1)	(166.3)
Tax pools, deferred financing, and compensation	(138.2)	(453.6)
Other	(161.2)	(209.9)
Valuation allowance	12	23.1
Net deferred income tax liabilities	$ 959.1	$ 957.9

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - CAD ($) $ in Millions	Jan. 01, 2022	Jan. 01, 2020	Jul. 01, 2019	Jan. 01, 2018	Jun. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Contingency
Statutory income tax rate (percent)						26.50%	27.00%
Tax-affected non-capital losses						$ 170.4
Canada Revenue Agency
Income Tax Contingency
Statutory income tax rate (percent)			11.00%		12.00%
Corporate tax rate (percent)				12.00%				11.00%
Canada Revenue Agency | Subsequent Event
Income Tax Contingency
Statutory income tax rate (percent)		10.00%
Forecasted decrease in effective tax rate (percent)		1.00%
Canada Revenue Agency | Subsequent Event | Forecast
Income Tax Contingency
Statutory income tax rate (percent)	8.00%

Income Taxes - Schedule of Unce

Income Taxes - Schedule of Uncertain Tax Positions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits
Balance, beginning of year	$ 2.2	$ 5.9
Net changes during the year	(0.2)	(3.7)
Balance, end of year	$ 2	$ 2.2

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Details) $ in Millions, $ in Millions	Sep. 18, 2013USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 12.8	$ 21
Regulatory assets - non-current		486.7	663
Regulatory liabilities - current		145.5	114.9
Regulatory liabilities - non-current		1,383.2	1,392.8
Fair value adjustment		79.8	87.3
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 60.2	71.2
Recovery period (years)		1 year
Refundable tax credit
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 1.9	3.8
Regulatory liabilities - non-current		$ 3.9	6.1
Gas storage facility tax credit	$ 15
Recovery period (years)		1 year
Virginia Rate Refund
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 40.4	0
Recovery period (years)		1 year
Federal income tax rate change
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 33.1	26.2
Regulatory liabilities - non-current		$ 628.3	698.4
Recovery period (years)		1 year
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		$ 261.2	166.7
Future removal and site restoration costs
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		483.9	514.7
Deferred gain on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		1.6	1.8
Accelerated replacement recovery mechanisms
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 0.4	5.2
Recovery period (years)		1 year
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 0.4	2.3
Recovery period (years)		1 year
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 9.1	6.2
Regulatory liabilities - non-current		$ 4.3	5.1
Recovery period (years)		1 year
Refundable tax credit noncurrent
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		2 years
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 7.6	20.4
Recovery period (years)		1 year
Accelerated replacement recovery mechanisms
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 2.5	0
Recovery period (years)		1 year
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 2.7	0.6
Recovery period (years)		1 year
Deferred regulatory costs and rate stabilization adjustment mechanism
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 149.5	215.5
Deferred regulatory costs and rate stabilization adjustment mechanism | Minimum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		1 year
Deferred regulatory costs and rate stabilization adjustment mechanism | Maximum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		51 years
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 128.2	192.9
Future recovery of non-retirement employee benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		19.4	21.3
Deferred pension costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		0	7.8
Deferred environmental costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		17.7	19.9
Deferred loss on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		99.2	109.3
Deferred future income taxes
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		42.7	67
Energy efficiency program - Maryland
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		12.1	4.6
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 17.9	$ 24.7

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	$ 7,640.2
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(334.1)	$ 379.9
Balance, end of year	7,368.8	7,640.2
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	579	199.1
OCI before reclassification	(323.5)	355.9
Amounts reclassified from AOCI	1.1	0.7
Adoption Of ASU No. 2016-01 (note 2)		7.1
Curtailment of DB and PRB plan		4.2
Current period OCI (pre-tax)	(322.4)	367.9
Income tax on amounts retained in AOCI	(11.4)	13.7
Income tax on amounts reclassified to earnings	(0.3)	(0.2)
Income tax on amounts related to curtailment of DB and PRB plan		(1.5)
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(334.1)	379.9
Balance, end of year	244.9	579
Available-for-sale
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	0	(7.1)
OCI before reclassification	0	0
Amounts reclassified from AOCI	0	0
Adoption Of ASU No. 2016-01 (note 2)		7.1
Curtailment of DB and PRB plan		0
Current period OCI (pre-tax)	0	7.1
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0	0
Income tax on amounts related to curtailment of DB and PRB plan		0
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	0	7.1
Balance, end of year	0	0
Defined benefit pension and PRB plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(19)	(11.4)
OCI before reclassification	15.2	(14.1)
Amounts reclassified from AOCI	1.1	0.7
Adoption Of ASU No. 2016-01 (note 2)		0
Curtailment of DB and PRB plan		4.2
Current period OCI (pre-tax)	16.3	(9.2)
Income tax on amounts retained in AOCI	(3.2)	3.3
Income tax on amounts reclassified to earnings	(0.3)	(0.2)
Income tax on amounts related to curtailment of DB and PRB plan		(1.5)
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	12.8	(7.6)
Balance, end of year	(6.2)	(19)
Hedge net investments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(209.2)	(129)
OCI before reclassification	68.2	(90.6)
Amounts reclassified from AOCI	0	0
Adoption Of ASU No. 2016-01 (note 2)		0
Curtailment of DB and PRB plan		0
Current period OCI (pre-tax)	68.2	(90.6)
Income tax on amounts retained in AOCI	(8.2)	10.4
Income tax on amounts reclassified to earnings	0	0
Income tax on amounts related to curtailment of DB and PRB plan		0
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	60	(80.2)
Balance, end of year	(149.2)	(209.2)
Translation foreign operations
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	801.4	342.9
OCI before reclassification	(406.2)	458.5
Amounts reclassified from AOCI	0	0
Adoption Of ASU No. 2016-01 (note 2)		0
Curtailment of DB and PRB plan		0
Current period OCI (pre-tax)	(406.2)	458.5
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0	0
Income tax on amounts related to curtailment of DB and PRB plan		0
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(406.2)	458.5
Balance, end of year	395.2	801.4
Equity investee
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	5.8	3.7
OCI before reclassification	(0.7)	2.1
Amounts reclassified from AOCI	0	0
Adoption Of ASU No. 2016-01 (note 2)		0
Curtailment of DB and PRB plan		0
Current period OCI (pre-tax)	(0.7)	2.1
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0	0
Income tax on amounts related to curtailment of DB and PRB plan		0
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(0.7)	2.1
Balance, end of year	$ 5.1	$ 5.8

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income - Summary of Reclassification from Accumulated Other Comprehensive Income (Details) - Total - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Defined benefit pension and PRB plans	$ 1.1	$ 0.7
Deferred income taxes	(0.3)	(0.2)
Reclassifications from AOCI, net	$ 0.8	$ 0.5

Financial Instruments and Fin_3

Financial Instruments and Financial Risk Management - Schedule of Fair Value of Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	$ 86.6	$ 114.1
Risk management assets - non-current	39.1	57.7
Risk management liabilities - current	124.8	89.3
Risk management liabilities - non-current	167	213
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	45	45
Financial assets	175	225.2
Current portion of long-term debt	922.9	890.2
Long-term debt	5,927.8	8,066.9
Other current liabilities	15.4	11.2
Other long-term liabilities		2
Financial liabilities	7,157.9	9,272.6
Carrying Amount | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	81.4	99
Risk management assets - non-current	30.9	49
Equity securities	4.3	8.4
Risk management liabilities - current	120.6	72
Risk management liabilities - non-current	77	103.4
Carrying Amount | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	5.2	15.1
Risk management assets - non-current	8.2	8.7
Risk management liabilities - current	4.2	17.3
Risk management liabilities - non-current	90	109.6
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	46.1	45.2
Financial assets	176.1	225.4
Current portion of long-term debt	922.9	884.4
Long-term debt	6,263.8	8,040.3
Other current liabilities	15.4	11.2
Other long-term liabilities		2
Financial liabilities	7,493.9	9,240.2
Fair Value | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	81.4	99
Risk management assets - non-current	30.9	49
Equity securities	4.3	8.4
Risk management liabilities - current	120.6	72
Risk management liabilities - non-current	77	103.4
Fair Value | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	5.2	15.1
Risk management assets - non-current	8.2	8.7
Risk management liabilities - current	4.2	17.3
Risk management liabilities - non-current	90	109.6
Fair Value | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	0	0
Financial assets	4.3	8.4
Current portion of long-term debt	0	0
Long-term debt	0	0
Other current liabilities	0	0
Other long-term liabilities		0
Financial liabilities	0	0
Fair Value | Level 1 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	0	0
Risk management assets - non-current	0	0
Equity securities	4.3	8.4
Risk management liabilities - current	0	0
Risk management liabilities - non-current	0	0
Fair Value | Level 1 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	0	0
Risk management assets - non-current	0	0
Risk management liabilities - current	0	0
Risk management liabilities - non-current	0	0
Fair Value | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	46.1	45.2
Financial assets	83.6	134.2
Current portion of long-term debt	922.9	884.4
Long-term debt	6,263.8	8,040.3
Other current liabilities	15.4	11.2
Other long-term liabilities		2
Financial liabilities	7,320.6	8,997.5
Fair Value | Level 2 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	30.4	68.3
Risk management assets - non-current	6.7	18
Equity securities	0	0
Risk management liabilities - current	98.7	41.3
Risk management liabilities - non-current	19.2	15.3
Fair Value | Level 2 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	0	2.7
Risk management assets - non-current	0.4	0
Risk management liabilities - current	0.6	2.9
Risk management liabilities - non-current	0	0.1
Fair Value | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	0	0
Financial assets	88.2	82.8
Current portion of long-term debt	0	0
Long-term debt	0	0
Other current liabilities	0	0
Other long-term liabilities		0
Financial liabilities	173.3	242.7
Fair Value | Level 3 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	51	30.7
Risk management assets - non-current	24.2	31
Equity securities	0	0
Risk management liabilities - current	21.9	30.7
Risk management liabilities - non-current	57.8	88.1
Fair Value | Level 3 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	5.2	12.4
Risk management assets - non-current	7.8	8.7
Risk management liabilities - current	3.6	14.4
Risk management liabilities - non-current	$ 90	$ 109.5

Financial Instruments and Fin_4

Financial Instruments and Financial Risk Management - Quantitative Information About The Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3 (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)$ / MW$ / dekatherm
Natural Gas | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Percent	29.00%
Natural Gas | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Percent	906.00%
Natural Gas | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (83.8)
Natural Gas | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(1.18)
Natural Gas | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	3.27
Natural Gas | Option Model
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (1.4)
Natural Gas | Option Model | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(1.19)
Natural Gas | Option Model | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	3.30
Electricity | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ 0.1
Electricity | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MW	(6.73)
Electricity | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MW	65.26

Financial Instruments and Fin_5

Financial Instruments and Financial Risk Management - Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3 (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	$ (163.2)	$ 0
Acquired (note 3)	0	(146.7)
Recorded in income	49	(14.8)
Recorded in regulatory assets	23.6	(5.9)
Transfers into Level 3	(9)	0
Transfers out of Level 3	12.3	7.3
Purchases	(11.4)	6.4
Settlements	7.3	(3.1)
Foreign exchange translation	6.3	(6.4)
Balance, end of year	(85.1)	(163.2)
Natural Gas
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	(148.5)	0
Acquired (note 3)	0	(136.1)
Recorded in income	47.6	(8.3)
Recorded in regulatory assets	23.6	(5.9)
Transfers into Level 3	(9)	0
Transfers out of Level 3	12.3	7.3
Purchases	0	0
Settlements	(17.1)	0.3
Foreign exchange translation	5.9	(5.8)
Balance, end of year	(85.2)	(148.5)
Electricity
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	(14.7)	0
Acquired (note 3)	0	(10.6)
Recorded in income	1.4	(6.5)
Recorded in regulatory assets	0	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Purchases	(11.4)	6.4
Settlements	24.4	(3.4)
Foreign exchange translation	0.4	(0.6)
Balance, end of year	$ 0.1	$ (14.7)

Financial Instruments and Fin_6

Financial Instruments and Financial Risk Management - Realized and Unrealized Losses Recorded to Income for Level 3 Measurements (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ 49	$ (14.8)
Commodity contracts | Recorded to revenue
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	75.2	(11.1)
Commodity contracts | Recorded to cost of sales
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ (26.2)	$ (3.7)

Financial Instruments and Fin_7

Financial Instruments and Financial Risk Management - Summary of Unrealized Gains (Losses) on Risk Management Contracts (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ (85.3)	$ 80.8
Natural gas
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	22.5	(2.2)
Energy exports
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(86.7)	0
NGL frac spread
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(17.4)	40
Power
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(4.9)	9.3
Foreign exchange
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ 1.2	$ 33.7

Financial Instruments and Fin_8

Financial Instruments and Financial Risk Management - Schedule of Offsetting Assets and Liabilities (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Offsetting Assets And Liabilities
Netting of collateral	$ 5,500,000	$ 0
Risk management assets - current	86,600,000	114,100,000
Risk management assets - non-current	39,100,000	57,700,000
Risk management liabilities - current	124,800,000	89,300,000
Risk management liabilities - non-current	167,000,000	213,000,000
Risk management contracts
Offsetting Assets And Liabilities
Gross amounts of recognized assets	184,700,000	262,300,000
Gross amounts offset in balance sheet	(63,400,000)	(90,500,000)
Netting of collateral	4,400,000	0
Net amount of assets presented in balance sheet	125,700,000	171,800,000
Gross amounts of recognized liabilities	386,000,000	394,900,000
Gross amounts offset in balance sheet	(63,400,000)	(90,500,000)
Netting of collateral	(30,800,000)	(2,100,000)
Net amount of liabilities presented in balance sheet	291,800,000	302,300,000
Natural gas
Offsetting Assets And Liabilities
Gross amounts of recognized assets	121,200,000	200,800,000
Gross amounts offset in balance sheet	(53,700,000)	(82,000,000)
Netting of collateral	0	0
Net amount of assets presented in balance sheet	67,500,000	118,800,000
Gross amounts of recognized liabilities	226,100,000	340,400,000
Gross amounts offset in balance sheet	(53,700,000)	(82,000,000)
Netting of collateral	(27,700,000)	(3,300,000)
Net amount of liabilities presented in balance sheet	144,700,000	255,100,000
Energy exports
Offsetting Assets And Liabilities
Gross amounts of recognized assets	9,700,000
Gross amounts offset in balance sheet	(2,700,000)
Netting of collateral	4,400,000
Net amount of assets presented in balance sheet	11,400,000
Gross amounts of recognized liabilities	89,500,000
Gross amounts offset in balance sheet	(2,700,000)
Netting of collateral	0
Net amount of liabilities presented in balance sheet	86,800,000
NGL frac spread
Offsetting Assets And Liabilities
Gross amounts of recognized assets	300,000	18,700,000
Gross amounts offset in balance sheet	(200,000)	(700,000)
Netting of collateral	0	0
Net amount of assets presented in balance sheet	100,000	18,000,000
Gross amounts of recognized liabilities	1,700,000	2,700,000
Gross amounts offset in balance sheet	(200,000)	(700,000)
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	1,500,000	2,000,000
Foreign exchange
Offsetting Assets And Liabilities
Gross amounts of recognized liabilities		1,200,000
Gross amounts offset in balance sheet		0
Netting of collateral		0
Net amount of liabilities presented in balance sheet		1,200,000
Power
Offsetting Assets And Liabilities
Gross amounts of recognized assets	53,500,000	42,800,000
Gross amounts offset in balance sheet	(6,800,000)	(7,800,000)
Netting of collateral	0	0
Net amount of assets presented in balance sheet	46,700,000	35,000,000
Gross amounts of recognized liabilities	68,700,000	50,600,000
Gross amounts offset in balance sheet	(6,800,000)	(7,800,000)
Netting of collateral	(3,100,000)	1,200,000
Net amount of liabilities presented in balance sheet	$ 58,800,000	$ 44,000,000

Financial Instruments and Fin_9

Financial Instruments and Financial Risk Management - Collateral Not Offset Against Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Collateral posted with counterparties	$ 29.1	$ 27.6
Cash collateral held representing an obligation	$ 0.3	$ 0.8

Financial Instruments and Fi_10

Financial Instruments and Financial Risk Management - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Netting of collateral				$ 5,500,000		$ 0
Long term debt				$ 6,850,700,000		$ 8,957,100,000
Other comprehensive income (loss)	$ (334,100,000)	$ 379,900,000
Unrealized gain on net investment hedge	60,000,000	(80,200,000)
Unrealized gains (losses) on risk management contracts	(85,300,000)	80,800,000
Interest rate risk
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Fixed rate debt, percent			76.00%	76.00%	59.00%	59.00%
Weather related instruments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Unrealized gains (losses) on risk management contracts	(1,900,000)	(1,000,000)
Net investment hedge
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Long term debt			$ 300		$ 1,494
Hedge net investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Other comprehensive income (loss)	$ 60,000,000	$ (80,200,000)

Financial Instruments and Fi_11

Financial Instruments and Financial Risk Management - Risk Management Liabilities And Maximum Potential Collateral Requirements (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk management liabilities with credit-risk-contingent features	$ 42.2	$ 14.7
Maximum potential collateral requirements	$ 29	$ 7.5

Financial Instruments and Fi_12

Financial Instruments and Financial Risk Management - Schedule of Fixed and Market Price Contract (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)kJMWh$ / gigajoule$ / MWh$ / barrelbbl	Dec. 31, 2018CAD ($)kJMWh$ / gigajoule$ / MWh$ / barrelbbl
Natural gas | Sales
Derivative
Notional volume (GJ) | kJ	698,126,985	858,640,810
Fair Value ($)	$ 28.9	$ 19
Natural gas | Sales | Minimum
Derivative
Fixed price | $ / gigajoule	1.32	1.07
Period (months)	1 month	1 month
Natural gas | Sales | Maximum
Derivative
Fixed price | $ / gigajoule	6.81	12.19
Period (months)	166 months	178 months
Natural gas | Purchases
Derivative
Notional volume (GJ) | kJ	1,406,991,689	1,638,207,391
Fair Value ($)	$ (104.4)	$ (179.5)
Natural gas | Purchases | Minimum
Derivative
Fixed price | $ / gigajoule	0.22	0.69
Period (months)	1 month	1 month
Natural gas | Purchases | Maximum
Derivative
Fixed price | $ / gigajoule	6.81	16.26
Period (months)	167 months	179 months
Natural gas | Swaps
Derivative
Notional volume (GJ) | kJ	541,652,374	621,578,572
Fair Value ($)	$ (1.7)	$ 20.9
Natural gas | Swaps | Minimum
Derivative
Fixed price | $ / gigajoule	0.22	2.56
Period (months)	1 month	1 month
Natural gas | Swaps | Maximum
Derivative
Fixed price | $ / gigajoule	10.24	15.37
Period (months)	51 months	231 months
Energy exports | Swaps
Derivative
Notional volume (Bbl) | bbl	9,374,826
Fair Value ($)	$ (75.4)
Energy exports | Swaps | Minimum
Derivative
Fixed price | $ / barrel	21.49
Period (months)	1 month
Energy exports | Swaps | Maximum
Derivative
Fixed price | $ / barrel	29.71
Period (months)	27 months
NGL frac spread | Swaps | Propane
Derivative
Notional volume (Bbl) | bbl		1,725,114
Fair Value ($)		$ 12.6
NGL frac spread | Swaps | Butane swaps
Derivative
Notional volume (Bbl) | bbl	346,852	74,371
Fair Value ($)	$ (0.5)	$ 1.2
NGL frac spread | Swaps | Crude oil swaps
Derivative
Notional volume (Bbl) | bbl	212,587	329,230
Fair Value ($)	$ (0.9)	$ 6
NGL frac spread | Swaps | Gas purchase
Derivative
Notional volume (GJ) | kJ	3,883,992	9,490,365
Fair Value ($)	$ 0	$ (3.8)
NGL frac spread | Swaps | Minimum | Propane
Derivative
Fixed price | $ / barrel		38.89
Period (months)		1 month
NGL frac spread | Swaps | Minimum | Butane swaps
Derivative
Fixed price | $ / barrel	73.02	52.95
Period (months)	1 month	1 month
NGL frac spread | Swaps | Minimum | Crude oil swaps
Derivative
Fixed price | $ / barrel	73.02	79.64
Period (months)	1 month	1 month
NGL frac spread | Swaps | Minimum | Gas purchase
Derivative
Fixed price | $ / gigajoule	1.58	1.38
Period (months)	1 month	1 month
NGL frac spread | Swaps | Maximum | Propane
Derivative
Fixed price | $ / barrel		47.63
Period (months)		12 months
NGL frac spread | Swaps | Maximum | Butane swaps
Derivative
Fixed price | $ / barrel	75.15	55.26
Period (months)	12 months	12 months
NGL frac spread | Swaps | Maximum | Crude oil swaps
Derivative
Fixed price | $ / barrel	75.15	86.28
Period (months)	12 months	12 months
NGL frac spread | Swaps | Maximum | Gas purchase
Derivative
Fixed price | $ / gigajoule	1.86	1.68
Period (months)	12 months	12 months
Power | Sales
Derivative
Notional volume (GJ) | MWh	8,034,024	11,881,575,000,000
Fair Value ($)	$ 39	$ (1.9)
Power | Sales | Minimum
Derivative
Fixed price | $ / MWh	31.63	26.90
Period (months)	1 month	1 month
Power | Sales | Maximum
Derivative
Fixed price | $ / MWh	66.76	95.03
Period (months)	42 months	60 months
Power | Purchases
Derivative
Notional volume (GJ) | MWh	8,552,467	8,507,874,000,000
Fair Value ($)	$ (27.3)	$ 16.4
Power | Purchases | Minimum
Derivative
Fixed price | $ / MWh	31.63	25.50
Period (months)	1 month	1 month
Power | Purchases | Maximum
Derivative
Fixed price | $ / MWh	66.76	50.25
Period (months)	60 months	42 months
Power | Swaps
Derivative
Notional volume (GJ) | MWh	25,058,577	20,957,180,000,000
Fair Value ($)	$ (23.8)	$ (22.3)
Power | Swaps | Minimum
Derivative
Fixed price | $ / MWh	(7.88)	(6.07)
Period (months)	1 month	1 month
Power | Swaps | Maximum
Derivative
Fixed price | $ / MWh	74.26	76.18
Period (months)	48 months	48 months

- Summary of Potential Impact o

- Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)$ / MWh$ / gigajoule$ / gigajoule$ / MWh$ / barrel	Dec. 31, 2018CAD ($)
Derivative
Unrealized gains (losses) on risk management contracts	$ (85.3)	$ 80.8
Alberta power price
Derivative
Increase or decrease to forward prices, energy | $ / MWh	1
Unrealized gains (losses) on risk management contracts	$ 2.3
PJM power price
Derivative
Increase or decrease to forward prices, energy | $ / MWh	1
Unrealized gains (losses) on risk management contracts	$ 1.9
AECO natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.5
Unrealized gains (losses) on risk management contracts	$ 1.1
NYMEX natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.5
Unrealized gains (losses) on risk management contracts	$ 2.6
Energy exports | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ 3.4
Baltic LPG Freight | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ 6.1
NGL frac spread
Derivative
Unrealized gains (losses) on risk management contracts	$ (17.4)	$ 40
NGL frac spread | Western Texas Intermediate (WTI) crude oil
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ 0.6
NGL frac spread | Gas purchase
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.5
Unrealized gains (losses) on risk management contracts	$ 1.9

Financial Instruments and Fi_13

Financial Instruments and Financial Risk Management - Schedule of Accounts Receivable Past Due or Impaired (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable
AR accruals	$ 447.5	$ 343.5
Receivables impaired	0	0
Allowance for credit losses	(54.7)	(33.2)	$ (2.4)
Accounts receivable	1,547.5	1,222.4
WGL Holdings
Accounts, Notes, Loans and Financing Receivable
Allowance credit losses acquired	52.9
Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	989	775.2
31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	74.1	61.2
61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	12.8	11.6
Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	24.1	30.9
Trade receivable
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	1,574.6	1,238.2
AR accruals	447.5	343.5
Receivables impaired	54.7	33.2
Trade receivable | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	961.5	757.9
Trade receivable | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	74.1	61.2
Trade receivable | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	12.8	11.6
Trade receivable | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	24	30.8
Other
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	27.6	17.4
AR accruals	0	0
Receivables impaired	0	0
Other | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	27.5	17.3
Other | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0	0
Other | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0	0
Other | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0.1	0.1
Allowance for credit losses
Accounts, Notes, Loans and Financing Receivable
AR accruals	0	0
Allowance for credit losses	(54.7)	(33.2)
Allowance for credit losses | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	$ 0	$ 0

Financial Instruments and Fi_14

Financial Instruments and Financial Risk Management - Allowance for Credit Loss (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Balance, beginning of year
Balance, beginning of year	$ 54.7	$ 2.4
Foreign exchange translation	(2.6)	0.1
New allowance	27.5	53.1
Change in allowance	(9.2)	(0.9)
Allowance applied to uncollectible customer accounts	(37.2)	0
Balance, end of year	33.2	$ 54.7
Disposal group, allowance for doubtful receivables	$ 8.1

Financial Instruments and Fi_15

Financial Instruments and Financial Risk Management - Schedule of Contractual Maturities for Financial Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Contractual maturities by period
Total	$ 8,907.3	$ 11,938.9
Less than 1 year	2,867.8	3,709.1
1-3 years	1,523.3	3,178.7
4-5 years	934.5	1,625.9
After 5 years	3,581.7	3,425.2
Accounts payable and accrued liabilities
Contractual maturities by period
Total	1,324.9	1,488.2
Less than 1 year	1,324.9	1,488.2
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Dividends payable
Contractual maturities by period
Total	22.3	22
Less than 1 year	22.3	22
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Short-term debt
Contractual maturities by period
Total	460	1,209.9
Less than 1 year	460	1,209.9
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Other current liabilities
Contractual maturities by period
Total	15.4	11.2
Less than 1 year	15.4	11.2
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Other long-term liabilities
Contractual maturities by period
Total		2
Less than 1 year		0
1-3 years		2
4-5 years		0
After 5 years		0
Risk management contract liabilities
Contractual maturities by period
Total	291.8	302.3
Less than 1 year	124.8	89.3
1-3 years	34.1	113.3
4-5 years	13.2	33.3
After 5 years	119.7	66.4
Current portion of long-term debt
Contractual maturities by period
Total	920.4	888.5
Less than 1 year	920.4	888.5
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Long-term debt
Contractual maturities by period
Total	5,872.5	8,014.8
Less than 1 year	0	0
1-3 years	1,489.2	3,063.4
4-5 years	921.3	1,592.6
After 5 years	$ 3,462	$ 3,358.8

Revenue - Disaggregation of Rev

Revenue - Disaggregation of Revenue by Major Sources (Details) - CAD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue
Revenue from contracts with customers		$ 4,940.5	$ 3,123.8
Other sources of revenue		554.5	1,132.9
Total revenue		5,495	4,256.7
Contract term	20 years
Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		2,225.1	1,162.7
Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		145	205
Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		2,501.4	1,684.3
Storage services
Disaggregation of Revenue
Revenue from contracts with customers		28.1	35.4
Other
Disaggregation of Revenue
Revenue from contracts with customers		40.9	36.4
Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		29.5	21.7
Leasing revenue
Disaggregation of Revenue
Other sources of revenue		242.6	452.1
Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		262.3	644.2
Other
Disaggregation of Revenue
Other sources of revenue		20.1	14.9
Utilities
Disaggregation of Revenue
Total revenue		2,564.2	1,752.6
Midstream
Disaggregation of Revenue
Total revenue		1,574.3	1,344.6
Midstream | Risk management and trading activities | GAIL
Disaggregation of Revenue
Total revenue		504.5	264.2
Power
Disaggregation of Revenue
Total revenue		1,356.3	1,162
Corporate
Disaggregation of Revenue
Total revenue		0.2	(2.5)
Operating Segments
Disaggregation of Revenue
Total revenue		5,539.4	4,369.2
Operating Segments | Utilities
Disaggregation of Revenue
Revenue from contracts with customers		2,538.7	1,730.4
Other sources of revenue		25.5	22.2
Total revenue		2,590.8	1,765.6
Operating Segments | Utilities | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Utilities | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Utilities | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		2,501.4	1,684.3
Operating Segments | Utilities | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		28.1	35.4
Operating Segments | Utilities | Other
Disaggregation of Revenue
Revenue from contracts with customers		9.2	10.7
Operating Segments | Utilities | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		29.5	21.7
Operating Segments | Utilities | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		0.9	0.6
Operating Segments | Utilities | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		0	1
Operating Segments | Utilities | Other
Disaggregation of Revenue
Other sources of revenue		(4.9)	(1.1)
Operating Segments | Midstream
Disaggregation of Revenue
Revenue from contracts with customers		1,241.4	870.8
Other sources of revenue		332.9	473.8
Total revenue		1,581.2	1,435
Operating Segments | Midstream | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		$ 1,093.7	665.2
Contract term		1 year
Operating Segments | Midstream | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		$ 145	205
Operating Segments | Midstream | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Midstream | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Midstream | Other
Disaggregation of Revenue
Revenue from contracts with customers		2.7	0.6
Operating Segments | Midstream | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0	0
Operating Segments | Midstream | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		136.6	96.6
Operating Segments | Midstream | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		196.2	377.6
Operating Segments | Midstream | Other
Disaggregation of Revenue
Other sources of revenue		0.1	(0.4)
Operating Segments | Power
Disaggregation of Revenue
Revenue from contracts with customers		1,160.4	522.6
Other sources of revenue		195.9	639.4
Total revenue		1,367.2	1,171
Operating Segments | Power | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		1,131.4	497.5
Operating Segments | Power | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Power | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Power | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Power | Other
Disaggregation of Revenue
Revenue from contracts with customers		29	25.1
Operating Segments | Power | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0	0
Operating Segments | Power | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		105.1	354.9
Operating Segments | Power | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		65.9	268.5
Operating Segments | Power | Other
Disaggregation of Revenue
Other sources of revenue		24.9	16
Operating Segments | Corporate
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Other sources of revenue		0.2	(2.5)
Total revenue		0.2	(2.4)
Operating Segments | Corporate | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate | Other
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0	0
Operating Segments | Corporate | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		0	0
Operating Segments | Corporate | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		0.2	(2.9)
Operating Segments | Corporate | Other
Disaggregation of Revenue
Other sources of revenue		$ 0	$ 0.4

Revenue - Narrative (Details)

Revenue - Narrative (Details) - CAD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue
Contract term	20 years
Contract asset, non current		$ 30	$ 11.5
Contract asset, current		58.6	47.3
Contract liability		$ 1.7	$ 2.2
Midstream | Operating Segments | Commodity sales contracts
Disaggregation of Revenue
Contract term		1 year
Midstream | Operating Segments | Commodity sales contracts | Residential, commercial, and industrial | Minimum
Disaggregation of Revenue
Contract term			1 year
Midstream | Operating Segments | Commodity sales contracts | Residential, commercial, and industrial | Maximum
Disaggregation of Revenue
Contract term			5 years
Power | Operating Segments | Commodity sales contracts
Disaggregation of Revenue
Long-term Purchase Commitment, Period		20 years

Revenue - Contract Assets and L

Revenue - Contract Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Change in Contract with Customer, Asset
Balance, beginning of year	$ 58.8	$ 0
Additions	32.3	130.1
Transfers to held for sale	0	(72.2)
Transfers to accounts receivable	0	(3.7)
Foreign exchange translation	(2.5)	4.6
Balance, end of year	88.6	58.8
Change in Contract with Customer, Liability
Balance, beginning of year	2.2	0
Additions	1.9	2.6
Revenue recognized from contract liabilities	(2.2)	(0.5)
Foreign exchange translation	(0.2)	0.1
Balance, end of year	$ 1.7	$ 2.2

Revenue - Schedule of Estimated

Revenue - Schedule of Estimated Revenue Related to Performance Obligations (Details) $ in Millions	Dec. 31, 2019CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 156.7
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 113.1
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 24.2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 19.4
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 122.9
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 89.8
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 24.2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 8.9
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 114.4
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 88.9
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23.5
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 111.7
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 86.5
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23.2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 111.6
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 86.4
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23.2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,152.3
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 971.9
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 168.4
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 12
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,769.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	1,436.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	286.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 46.3

Shareholders_ Equity - Schedule

Shareholders’ Equity - Schedule of Common Shares Issued and Outstanding (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Stockholders' Equity
Balance, beginning of year		$ 7,019.6
Beginning balance (shares)		275,200,000
Shares issued for cash on exercise of options (shares)		76,177	57,275
Ending balance (shares)		279,100,000	275,200,000
Balance at end of year		$ 7,214.9	$ 7,019.6
Common stock
Increase (Decrease) in Stockholders' Equity
Balance, beginning of year		$ 6,653.9	$ 4,007.9
Beginning balance (shares)		275,224,066	175,279,216
Shares issued on conversion of subscription receipts, net of issuance costs			$ 2,305.6
Shares issued on conversion of subscription receipts, net of issuance costs (shares)			84,510,000
Shares issued for cash on exercise of options, Amount		$ 1.2	$ 1.3
Shares issued for cash on exercise of options (shares)		76,177	57,275
Deferred taxes on share issuance cost		$ (3.9)	$ 13.3
Shares issued under DRIP	[1]	$ 67.8	$ 325.8
Shares issued under DRIP (shares)		3,774,442	15,377,575
Ending balance (shares)		279,074,685	275,224,066
Balance at end of year		$ 6,719	$ 6,653.9
[1]	Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan.

- Schedule of Preferred Shares

- Schedule of Preferred Shares Issued and Outstanding (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)shares	Dec. 31, 2019$ / shares	Dec. 31, 2019CAD ($)shares
Class of Stock
Preferred stock, value		$ 7,019.6		$ 7,214.9
Fair value adjustment on WGL Acquisition (note 3)		$ 89		$ 84.3
Preferred shares
Class of Stock
Preferred stock, shares | shares		52,280,600		52,000,000
Preferred stock, value		$ 1,318.8		$ 1,277.1
Share issuance costs, net of taxes	$ (28.5)	(27.9)
Fair value adjustment on WGL Acquisition (note 3)		$ 4.1		$ 0
Preferred shares | Series A
Class of Stock
Preferred stock, shares | shares		5,511,220		5,511,220
Preferred stock, value		$ 137.8		$ 137.8
Preferred shares | Series B
Class of Stock
Preferred stock, shares | shares		2,488,780		2,488,780
Preferred stock, value		$ 62.2		$ 62.2
Preferred shares | Series C
Class of Stock
Preferred stock, shares | shares		8,000,000		8,000,000
Preferred stock, value		$ 205.6		$ 205.6
Preferred shares | Series E
Class of Stock
Preferred stock, shares | shares		8,000,000		8,000,000
Preferred stock, value		$ 200		$ 200
Preferred shares | Series G
Class of Stock
Preferred stock, shares | shares		8,000,000		6,885,823
Preferred stock, value		$ 200		$ 172.1
Preferred shares | Series H
Class of Stock
Preferred stock, shares | shares		0		1,114,177
Preferred stock, value		$ 0		$ 27.9
Preferred shares | Series I
Class of Stock
Preferred stock, shares | shares		8,000,000		8,000,000
Preferred stock, value		$ 200		$ 200
Preferred shares | Series K
Class of Stock
Preferred stock, shares | shares		12,000,000		12,000,000
Preferred stock, value		$ 300		$ 300
Preferred shares | $4.80 series | Washington Gas
Class of Stock
Preferred stock, shares | shares		150,000		0
Preferred stock, value		$ 19.7		$ 0
Preferred stock par value (usd per share) | $ / shares			$ 4.80
Preferred shares | $4.25 series | Washington Gas
Class of Stock
Preferred stock, shares | shares		70,600		0
Preferred stock, value		$ 9.4		$ 0
Preferred stock par value (usd per share) | $ / shares			4.25
Preferred shares | $5.00 series | Washington Gas
Class of Stock
Preferred stock, shares | shares		60,000		0
Preferred stock, value		$ 7.9		$ 0
Preferred stock par value (usd per share) | $ / shares			$ 5

Shareholders_ Equity - Narrativ

Shareholders’ Equity - Narrative (Details)	Dec. 20, 2019CAD ($)	Dec. 31, 2019$ / shares	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)shares	Dec. 31, 2019CAD ($)planshares	Dec. 31, 2017shares
Share-based Compensation Arrangement by Share-based Payment Award
Number of dividend reinvestment plans (plan) | plan					2
Equity discount rate (percent)					3.00%
Gain on redemption of preferred shares	$ 3,500,000		$ 3,500,000	$ 0
Common shares outstanding (shares) | shares				275,200,000	279,100,000
Balacne outstanding (units) | shares				9,908,154	6,484,831	564,549
Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Shares reserved for issuance | shares					13,915,160
Unexpensed fair value of share option compensation cost				$ 3,700,000	$ 4,500,000
Aggregate intrinsic value of options exercisable				0	3,300,000
Intrinsic value of options outstanding				0	12,100,000
Intrinsic value of options exercised			$ 400,000	300,000
Mid-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period			36 months
Mid-Term Incentive And Deferred Share Unit Plans
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense			$ 21,700,000	16,600,000
Unrecognized compensation expense				$ 26,900,000	$ 21,800,000
Minimum | Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options term			6 years
Maximum | Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options term			10 years
Vesting period			4 years
Washington Gas
Share-based Compensation Arrangement by Share-based Payment Award
Price per unit acquired (per unit) | $ / shares		$ 1
Balacne outstanding (units) | shares				8,866,795	4,920,510
Preferred shares | Washington Gas | $4.25 series
Share-based Compensation Arrangement by Share-based Payment Award
Preferred stock par value (usd per share) | $ / shares		4.25
Preferred shares | Washington Gas | $4.80 series
Share-based Compensation Arrangement by Share-based Payment Award
Preferred stock par value (usd per share) | $ / shares		4.80
Preferred shares | Washington Gas | $5.00 series
Share-based Compensation Arrangement by Share-based Payment Award
Preferred stock par value (usd per share) | $ / shares		$ 5

Shareholders_ Equity - Summary

Shareholders’ Equity - Summary of Cumulative Redeemable Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2019$ / sharesshares	Dec. 31, 2019$ / shares$ / sharesshares	Dec. 31, 2019$ / sharesshares	Oct. 01, 2019$ / shares	Oct. 01, 2015$ / shares
Series A
Class of Stock
Current Yield	3.38%	3.38%
Annual dividend per share		$ 0.84500
Redemption price (per share)			$ 25
Series A | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	2.66%	2.66%	2.66%
Series B
Class of Stock
Redemption price (per share)			$ 25		$ 25.50
Series B | 90-Day government of Canada treasury bill rate
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	2.66%	2.66%	2.66%
Preferred stock floating dividend rate (per share)			$ 0.26803
Series C
Class of Stock
Current Yield	5.29%	5.29%
Annual dividend per share	$ 1.32250
Redemption price (per share)	$ 25	$ 25
Series C | Five year United States government bond
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.58%	3.58%	3.58%
Series E
Class of Stock
Current Yield	5.393%	5.393%
Annual dividend per share		$ 1.34825
Redemption price (per share)			$ 25
Series E | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.17%	3.17%	3.17%
Series G
Class of Stock
Current Yield	4.62%	4.62%
Annual dividend per share		$ 1.15575
Redemption price (per share)			$ 25
Series G | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.06%	3.06%	3.06%
Series H
Class of Stock
Redemption price (per share)			$ 25	$ 25.50
Series H | 90-Day government of Canada treasury bill rate
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.06%	3.06%	3.06%
Preferred stock floating dividend rate (per share)			$ 0.29289
Series I
Class of Stock
Current Yield	5.25%	5.25%
Annual dividend per share		$ 1.31250
Redemption price (per share)			$ 25
Series I | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	4.19%	4.19%	4.19%
Series I | Five year government of Canada bond yield | Minimum
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	5.25%	5.25%	5.25%
Series K
Class of Stock
Current Yield	5.00%	5.00%
Annual dividend per share		$ 1.25000
Redemption price (per share)			$ 25
Series K | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.80%	3.80%	3.80%
Series K | Five year government of Canada bond yield | Minimum
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	5.00%	5.00%	5.00%
Series F
Class of Stock
Redemption price (per share)			$ 25.5
Preferred stock shares authorized (shares) | shares	8,000,000	8,000,000	8,000,000
Series J
Class of Stock
Redemption price (per share)			$ 25.5
Preferred stock shares authorized (shares) | shares	8,000,000	8,000,000	8,000,000
Series D
Class of Stock
Redemption price (per share)			$ 25.50
Preferred stock shares authorized (shares) | shares	8,000,000	8,000,000	8,000,000
Series L
Class of Stock
Redemption price (per share)			$ 25.50
Series L | Maximum
Class of Stock
Preferred stock shares authorized (shares) | shares	12,000,000	12,000,000	12,000,000

Shareholders_ Equity - Summar_2

Shareholders’ Equity - Summary of Share Option Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Number of options
Share options outstanding, beginning of year (shares)	6,309,183	4,533,761
Granted (shares)	2,287,385	2,811,460
Exercised (shares)	(76,177)	(57,275)
Forfeited, Number of options	(1,165,435)	(878,013)
Expired, Number of options	(311,000)	(100,750)
Share options outstanding, end of year (shares)	7,043,956	6,309,183
Share options exercisable, end of year (shares)	2,921,641.666654	2,897,723,000,000
Exercise price
Share options outstanding, beginning of year (per share)	$ 25.18	$ 32.35
Granted (per share)	19.12	16.69
Exercised (per share)	14.52	20.68
Forfeited (per share)	27.31	36.47
Expired (per share)	36.16	14.60
Share options outstanding, end of year (per share)	22.49	25.18
Share options exercisable, end of year (per share)	$ 27.70	$ 32.01

Shareholders_ Equity - Summar_3

Shareholders’ Equity - Summary of Employee Share Option Plan (Details)	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Number outstanding (shares) | shares	7,043,956
Options outstanding, Weighted average exercise price (per share)	$ 22.49
Options outstanding, Weighted average remaining contractual life	4 years 1 month 9 days
Options exercisable, Number exercisable (shares) | shares	2,921,641.666654
Options exercisable, Weighted average exercise price (per share)	$ 27.70
Options exercisable, Weighted average remaining contractual life	2 years 9 months 6 days
$14.52 to $18.00
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 14.52
Options outstanding, Exercise price range, Upper limit (per share)	$ 18
Options outstanding, Number outstanding (shares) | shares	2,557,328
Options outstanding, Weighted average exercise price (per share)	$ 15.19
Options outstanding, Weighted average remaining contractual life	4 years 11 months 23 days
Options exercisable, Number exercisable (shares) | shares	638,384.666654
Options exercisable, Weighted average exercise price (per share)	$ 14.62
Options exercisable, Weighted average remaining contractual life	4 years 9 months 13 days
$18.01 to $25.08
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 18.01
Options outstanding, Exercise price range, Upper limit (per share)	$ 25.08
Options outstanding, Number outstanding (shares) | shares	1,961,805
Options outstanding, Weighted average exercise price (per share)	$ 19.78
Options outstanding, Weighted average remaining contractual life	4 years 9 months 7 days
Options exercisable, Number exercisable (shares) | shares	305,750
Options exercisable, Weighted average exercise price (per share)	$ 21.05
Options exercisable, Weighted average remaining contractual life	11 months 16 days
$25.09 to $46.70
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 25.09
Options outstanding, Exercise price range, Upper limit (per share)	$ 46.70
Options outstanding, Number outstanding (shares) | shares	2,524,823
Options outstanding, Weighted average exercise price (per share)	$ 32
Options outstanding, Weighted average remaining contractual life	2 years 8 months 18 days
Options exercisable, Number exercisable (shares) | shares	1,977,507
Options exercisable, Weighted average exercise price (per share)	$ 32.95
Options exercisable, Weighted average remaining contractual life	2 years 4 months 22 days

Shareholders_ Equity - Summar_4

Shareholders’ Equity - Summary of Fair Value Options Granted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Stockholders' Equity Note [Abstract]
Fair value per option (per share)	$ 2.30	$ 1.27
Risk-free interest rate (percent)	1.48%	1.99%
Expected life (years)	6 years	6 years
Expected volatility (percent)	24.84%	23.23%
Annual dividend per share (per share)	$ 0.96253	$ 1.18
Forfeiture rate (percent)	0.00%	0.00%

Shareholders_ Equity - Schedu_2

Shareholders’ Equity - Schedule of MTIP and DSUP Activity (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
PUs, RUs, and DSUs (number of units)
Balance, beginning of year (units)	9,908,154	564,549
Acquired (units)	0	5,291,621
Converted to cash (units)		(5,291,621)
Granted (units)	674,971	9,502,347
Vested and paid out (units)	(677,667)	(148,154)
Exercised (units)	(113,668)
Forfeited (units)	(3,377,962)	(66,522)
Units in lieu of dividends (units)	71,003	55,934
Outstanding, end of year (units)	6,484,831	9,908,154

Net Income (Loss) Per Common _3

Net Income (Loss) Per Common Share - Summary of Net Income per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	Dec. 20, 2019	Dec. 31, 2019	Dec. 31, 2018
Numerator:
Net income (loss) applicable to controlling interests		$ 833.5	$ (435.1)
Less: Preferred share dividends		(68.5)	(66.6)
Gain on redemption of preferred shares (note 25)	$ 3.5	3.5	0
Net income (loss) applicable to common shares		$ 768.5	$ (501.7)
Denominator:
Weighted average number of common shares outstanding (shares)		276.9	222.6
Dilutive equity instruments (shares)		0.5	0
Weighted average number of common shares outstanding - diluted (shares)		277.4	222.6
Basic net income (loss) per common share (per share)		$ 2.78	$ (2.25)
Diluted net income (loss) per common share (per share)		$ 2.77	$ (2.25)
Anti-dilutive share options excluded from diluted income per share (shares)		4.3	4

Other Income - Schedule of Othe

Other Income - Schedule of Other Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Other Income and Expenses [Abstract]
Gains (losses) from sale of assets	$ 875.8	$ (10.6)
Other components of net benefit cost (note 28)	27.4	18.9
Interest income and other revenue	9	2.7
Losses on investments	(4.1)	(10.1)
Total other income	$ 908.1	$ 0.9

Pension Plans and Retiree Ben_3

Pension Plans and Retiree Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)planage	Dec. 31, 2018CAD ($)
Defined Benefit Plan Disclosure
Defined contribution plan cost recorded | $	$ 19.8	$ 15.4
Rabbi trust | $	$ 57.4	$ 89.3
Assumed initial healthcare cost trend rate	6.30%
Minimum
Defined Benefit Plan Disclosure
Plan assets investment objective period	3 years
Ultimate trend rate	2.00%
Maximum
Defined Benefit Plan Disclosure
Plan assets investment objective period	5 years
Ultimate trend rate	4.50%
Defined Benefit | Canada
Defined Benefit Plan Disclosure
Number of pension plans	5
Defined Benefit | Canada | Fully funded
Defined Benefit Plan Disclosure
Number of pension plans	2
Defined Benefit | United States
Defined Benefit Plan Disclosure
Number of pension plans	6
Defined Benefit | United States | Fully funded
Defined Benefit Plan Disclosure
Number of pension plans	1
Post- Retirement Benefits | Canada
Defined Benefit Plan Disclosure
Number of pension plans	1
Post- Retirement Benefits | United States
Defined Benefit Plan Disclosure
Number of pension plans	4
Medical benefit eligibility age | age	65
Post- Retirement Benefits | United States | Partially funded
Defined Benefit Plan Disclosure
Number of pension plans	1
Post- Retirement Benefits | United States | Fully funded
Defined Benefit Plan Disclosure
Number of pension plans	3

Pension Plans and Retiree Ben_4

Pension Plans and Retiree Benefits - Summary of Defined Benefit Plans (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Plan assets
Plan assets, Fair value, end of year	$ 2,424.7
United States
Plan assets
Plan assets, Fair value, end of year	2,409.8
Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,669.6	$ 469.4
Plans disposed		(132.1)
Actuarial loss (gain)	184.1	(68.5)
Current service cost	26.4	18.6
Member contributions	0	0
Interest cost	69	39.2
Benefits paid	(81.3)	(45.9)
Expenses paid	(0.7)	(0.9)
Settlements	(24.7)
Plan combinations		1,312.4
Plan amendments	0.3	0
Other	0
Foreign exchange translation	(82)	77.4
Balance, end of year	1,760.7	1,669.6
Plan assets
Fair value, beginning of year	1,367.9	363.9
Plans disposed		(102.1)
Actual return on plan assets	285.1	(55)
Employer contributions	43	11
Member contributions	0	0
Benefits paid	(81.3)	(45.9)
Expenses paid	(0.7)	(0.9)
Settlements	(25.7)
Other	0
Plan combinations		1,133.5
Foreign exchange translation	(69.5)	63.4
Plan assets, Fair value, end of year	1,518.8	1,367.9
Funded status	(241.9)	(301.7)
Defined Benefit | Canada
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	34.3	165.6
Plans disposed		(132.1)
Actuarial loss (gain)	2.1	(0.8)
Current service cost	2.6	2.4
Member contributions	0	0
Interest cost	1.2	1.2
Benefits paid	(4)	(2.7)
Expenses paid	(0.1)	0
Settlements	0
Plan combinations		0.7
Plan amendments	0	0
Other	0
Foreign exchange translation	0	0
Balance, end of year	36.1	34.3
Plan assets
Fair value, beginning of year	13.8	115.2
Plans disposed		(102.1)
Actual return on plan assets	0.9	(0.3)
Employer contributions	4.3	3.4
Member contributions	0	0
Benefits paid	(4)	(2.7)
Expenses paid	(0.1)	0
Settlements	0
Other	0
Plan combinations		0.3
Foreign exchange translation	0	0
Plan assets, Fair value, end of year	14.9	13.8
Funded status	(21.2)	(20.5)
Defined Benefit | United States
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,635.3	303.8
Plans disposed		0
Actuarial loss (gain)	182	(67.7)
Current service cost	23.8	16.2
Member contributions	0	0
Interest cost	67.8	38
Benefits paid	(77.3)	(43.2)
Expenses paid	(0.6)	(0.9)
Settlements	(24.7)
Plan combinations		1,311.7
Plan amendments	0.3	0
Other	0
Foreign exchange translation	(82)	77.4
Balance, end of year	1,724.6	1,635.3
Plan assets
Fair value, beginning of year	1,354.1	248.7
Plans disposed		0
Actual return on plan assets	284.2	(54.7)
Employer contributions	38.7	7.6
Member contributions	0	0
Benefits paid	(77.3)	(43.2)
Expenses paid	(0.6)	(0.9)
Settlements	(25.7)
Other	0
Plan combinations		1,133.2
Foreign exchange translation	(69.5)	63.4
Plan assets, Fair value, end of year	1,503.9	1,354.1
Funded status	(220.7)	(281.2)
Post- Retirement Benefits
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	459.9	98.5
Plans disposed		(13.6)
Actuarial loss (gain)	(14.6)	(33.9)
Current service cost	8.5	5.4
Member contributions	2.2	2.1
Interest cost	19.2	11
Benefits paid	(24.5)	(13.4)
Expenses paid	(0.1)	(0.1)
Settlements	0
Plan combinations		382.9
Plan amendments	0	(0.4)
Other	1
Foreign exchange translation	(21.8)	21.4
Balance, end of year	429.8	459.9
Plan assets
Fair value, beginning of year	791.2	78.9
Plans disposed		(8.1)
Actual return on plan assets	177.4	(37.2)
Employer contributions	0.2	2.5
Member contributions	2.2	2.1
Benefits paid	(23.8)	(13.4)
Expenses paid	(0.1)	(0.1)
Settlements	0
Other	0.1
Plan combinations		732.7
Foreign exchange translation	(41.3)	33.8
Plan assets, Fair value, end of year	905.9	791.2
Funded status	476.1	331.3
Post- Retirement Benefits | Canada
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1.9	15.8
Plans disposed		(13.6)
Actuarial loss (gain)	0.2	(0.1)
Current service cost	0	0.1
Member contributions	0	0
Interest cost	0.1	0.1
Benefits paid	(0.1)	0
Expenses paid	0	0
Settlements	0
Plan combinations		0
Plan amendments	0	(0.4)
Other	0
Foreign exchange translation	0	0
Balance, end of year	2.1	1.9
Plan assets
Fair value, beginning of year	0	8.1
Plans disposed		(8.1)
Actual return on plan assets	0	0
Employer contributions	0.1	0
Member contributions	0	0
Benefits paid	(0.1)	0
Expenses paid	0	0
Settlements	0
Other	0
Plan combinations		0
Foreign exchange translation	0	0
Plan assets, Fair value, end of year	0	0
Funded status	(2.1)	(1.9)
Post- Retirement Benefits | United States
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	458	82.7
Plans disposed		0
Actuarial loss (gain)	(14.8)	(33.8)
Current service cost	8.5	5.3
Member contributions	2.2	2.1
Interest cost	19.1	10.9
Benefits paid	(24.4)	(13.4)
Expenses paid	(0.1)	(0.1)
Settlements	0
Plan combinations		382.9
Plan amendments	0	0
Other	1
Foreign exchange translation	(21.8)	21.4
Balance, end of year	427.7	458
Plan assets
Fair value, beginning of year	791.2	70.8
Plans disposed		0
Actual return on plan assets	177.4	(37.2)
Employer contributions	0.1	2.5
Member contributions	2.2	2.1
Benefits paid	(23.7)	(13.4)
Expenses paid	(0.1)	(0.1)
Settlements	0
Other	0.1
Plan combinations		732.7
Foreign exchange translation	(41.3)	33.8
Plan assets, Fair value, end of year	905.9	791.2
Funded status	$ 478.2	$ 333.2

Pension Plans and Retiree Ben_5

Pension Plans and Retiree Benefits - Schedule of Amount Included in the Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	$ 486.8	$ 341.4
Accounts payable and accrued liabilities	(25.7)	(27.6)
Future employee obligations	(226.9)	(284.2)
Total amounts included in Consolidated Balance Sheets	234.2	29.6
Defined Benefit
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	0	0
Accounts payable and accrued liabilities	(25.7)	(27.6)
Future employee obligations	(216.2)	(274.1)
Total amounts included in Consolidated Balance Sheets	(241.9)	(301.7)
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	486.8	341.4
Accounts payable and accrued liabilities	0	0
Future employee obligations	(10.7)	(10.1)
Total amounts included in Consolidated Balance Sheets	$ 476.1	$ 331.3

Pension Plans and Retiree Ben_6

Pension Plans and Retiree Benefits - Schedule of Funded Status Based on Accumulated Benefit Obligation (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Canada
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ (34.7)	$ (32.9)
United States
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ (1,616.4)	$ (1,525.6)

Pension Plans and Retiree Ben_7

Pension Plans and Retiree Benefits - Summary of Amounts Recorded in Other Comprehensive Income (Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit
Defined Benefit Plan Disclosure
Past service credit (cost)	$ (0.1)	$ (0.5)
Net actuarial gain (loss)	(24.3)	(19.4)
Recognized in AOCI pre-tax	(24.4)	(19.9)
Increase (decrease) by the amount included in deferred tax liabilities	9.3	4.6
Net amount in AOCI after-tax	(15.1)	(15.3)
Defined Benefit | Canada
Defined Benefit Plan Disclosure
Past service credit (cost)	(0.2)	(0.3)
Net actuarial gain (loss)	(9.4)	(8.7)
Recognized in AOCI pre-tax	(9.6)	(9)
Increase (decrease) by the amount included in deferred tax liabilities	2.3	2.4
Net amount in AOCI after-tax	(7.3)	(6.6)
Defined Benefit | United States
Defined Benefit Plan Disclosure
Past service credit (cost)	0.1	(0.2)
Net actuarial gain (loss)	(14.9)	(10.7)
Recognized in AOCI pre-tax	(14.8)	(10.9)
Increase (decrease) by the amount included in deferred tax liabilities	7	2.2
Net amount in AOCI after-tax	(7.8)	(8.7)
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit (cost)	0.3	0.4
Net actuarial gain (loss)	17.5	(5.5)
Recognized in AOCI pre-tax	17.8	(5.1)
Increase (decrease) by the amount included in deferred tax liabilities	(8.9)	1.4
Net amount in AOCI after-tax	8.9	(3.7)
Post- Retirement Benefits | Canada
Defined Benefit Plan Disclosure
Past service credit (cost)	0.3	0.4
Net actuarial gain (loss)	(0.7)	(0.5)
Recognized in AOCI pre-tax	(0.4)	(0.1)
Increase (decrease) by the amount included in deferred tax liabilities	0.1	0
Net amount in AOCI after-tax	(0.3)	(0.1)
Post- Retirement Benefits | United States
Defined Benefit Plan Disclosure
Past service credit (cost)	0	0
Net actuarial gain (loss)	18.2	(5)
Recognized in AOCI pre-tax	18.2	(5)
Increase (decrease) by the amount included in deferred tax liabilities	(9)	1.4
Net amount in AOCI after-tax	$ 9.2	$ (3.6)

Pension Plans and Retiree Ben_8

Pension Plans and Retiree Benefits - Summary of Amounts Recorded in A Regulatory Asset (Liability) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit
Defined Benefit Plan Disclosure
Past service cost (credit)	$ 1.1	$ 0.8
Net actuarial loss (gain)	127.1	188.2
Recognized in regulatory asset (liability)	128.2	189
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost (credit)	(105.4)	(110.2)
Net actuarial loss (gain)	(155.8)	(52.6)
Recognized in regulatory asset (liability)	(261.2)	(162.8)
Canada | Defined Benefit
Defined Benefit Plan Disclosure
Past service cost (credit)	0	0
Net actuarial loss (gain)	0	0
Recognized in regulatory asset (liability)	0	0
Canada | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost (credit)	0	0
Net actuarial loss (gain)	0	0
Recognized in regulatory asset (liability)	0	0
United States | Defined Benefit
Defined Benefit Plan Disclosure
Past service cost (credit)	1.1	0.8
Net actuarial loss (gain)	127.1	188.2
Recognized in regulatory asset (liability)	128.2	189
United States | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost (credit)	(105.4)	(110.2)
Net actuarial loss (gain)	(155.8)	(52.6)
Recognized in regulatory asset (liability)	$ (261.2)	$ (162.8)

Pension Plans and Retiree Ben_9

Pension Plans and Retiree Benefits - Summary of Amounts to be Amortized from AOCI in the Next Fiscal Year (Details) $ in Millions	Dec. 31, 2019CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Past service cost (credit)	$ 0.2
Actuarial loss	4
Total	4.2
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost (credit)	(0.7)
Actuarial loss	0.3
Total	$ (0.4)

Pension Plans and Retiree Be_10

Pension Plans and Retiree Benefits - Schedule of Amounts in Regulatory Assets (Liabilities) to be Recognized over Next Fiscal Year (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Past service credit (cost)	$ (0.2)
Actuarial gain (loss)	(17.1)
Total	(17.3)
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit (cost)	16.7
Actuarial gain (loss)	0.5
Total	$ 17.2

Pension Plans and Retiree Be_11

Pension Plans and Retiree Benefits - Schedule of Net Periodic Benefit Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	$ 26.4	$ 18.6
Interest cost	69	39.2
Expected return on plan assets	(75.1)	(50.4)
Amortization of past service cost (credit)	0.5	0.2
Amortization of net actuarial loss	12.6	8.3
Plan settlements	4.1
Other	0
Net benefit cost (income) recognized	37.5	15.9
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	8.5	5.4
Interest cost	19.2	11
Expected return on plan assets	(37.1)	(21.6)
Amortization of past service cost (credit)	(21.9)	(11.5)
Amortization of net actuarial loss	0.1	0.4
Plan settlements	0
Other	0.9
Net benefit cost (income) recognized	(30.3)	(16.3)
Canada | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	2.6	2.4
Interest cost	1.2	1.2
Expected return on plan assets	(0.5)	(0.5)
Amortization of past service cost (credit)	0.1	0.1
Amortization of net actuarial loss	0.9	0.6
Plan settlements	0
Other	0
Net benefit cost (income) recognized	4.3	3.8
Canada | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	0	0.1
Interest cost	0.1	0.1
Expected return on plan assets	0	0
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	0	0
Plan settlements	0
Other	0
Net benefit cost (income) recognized	0.1	0.2
United States | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	23.8	16.2
Interest cost	67.8	38
Expected return on plan assets	(74.6)	(49.9)
Amortization of past service cost (credit)	0.4	0.1
Amortization of net actuarial loss	11.7	7.7
Plan settlements	4.1
Other	0
Net benefit cost (income) recognized	33.2	12.1
United States | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	8.5	5.3
Interest cost	19.1	10.9
Expected return on plan assets	(37.1)	(21.6)
Amortization of past service cost (credit)	(21.9)	(11.5)
Amortization of net actuarial loss	0.1	0.4
Plan settlements	0
Other	0.9
Net benefit cost (income) recognized	$ (30.4)	$ (16.5)

Pension Plans and Retiree Be_12

Pension Plans and Retiree Benefits - Schedule of Collective Investment Mixes for Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2,445.9
Net payable	(21.2)
Fair value of Plan Assets	$ 2,424.7
Percentage of Plan Assets	100.00%
Percentage of Plan Asset before net payable	100.90%
Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,518.8	$ 1,367.9	$ 363.9
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	905.9	791.2	78.9
Commingled funds and pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 648.9
Percentage of Plan Asset before net payable	26.80%
Private Equity/Limited Partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 55.6
Percentage of Plan Asset before net payable	2.30%
Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 32
Percentage of Plan Asset before net payable		1.30%
Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 433.8
Percentage of Plan Asset before net payable		17.90%
Net payable
Defined Benefit Plan Disclosure
Percentage of Plan Assets payable	(0.90%)
Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,275.6
Percentage of Plan Assets	52.60%
Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12.7
Percentage of Plan Assets	0.50%
Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 6.7
Percentage of Plan Assets	0.30%
Fair value | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 304.9
Percentage of Plan Assets	12.60%
Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 938.7
Percentage of Plan Assets	38.70%
Fair value | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 0.8
Percentage of Plan Assets	0.00%
Fair value | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ (0.2)
Percentage of Plan Assets	0.00%
Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12
Percentage of Plan Assets	0.50%
Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 452.9
Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	12.7
Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	6.7
Level 1 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	304.6
Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	128.9
Level 1 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 1 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	822.7
Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.3
Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	809.8
Level 2 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.8
Level 2 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	(0.2)
Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12
Canada
Defined Benefit Plan Disclosure
Percentage of Plan Assets	100.00%
Canada | Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 14.9	$ 13.8	115.2
Canada | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 0	0	8.1
Canada | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Percentage of Plan Assets	12.80%
Canada | Equities | Canada
Defined Benefit Plan Disclosure
Percentage of Plan Assets	27.50%
Canada | Equities | United States
Defined Benefit Plan Disclosure
Percentage of Plan Assets	16.00%
Canada | Fixed income
Defined Benefit Plan Disclosure
Percentage of Plan Assets	38.30%
Canada | Fixed income | SEMCO
Defined Benefit Plan Disclosure
Target asset mix	33.00%
Canada | Fixed income | Minimum
Defined Benefit Plan Disclosure
Target asset mix	45.00%
Canada | Fixed income | Minimum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix	50.00%
Canada | Fixed income | Maximum
Defined Benefit Plan Disclosure
Target asset mix	55.00%
Canada | Fixed income | Maximum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix	60.00%
Canada | Real estate
Defined Benefit Plan Disclosure
Percentage of Plan Assets	5.40%
Canada | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 14.9
Canada | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	1.9
Canada | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	4.1
Canada | Fair value | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	2.4
Canada | Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	5.7
Canada | Fair value | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.8
Canada | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	14.1
Canada | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	1.9
Canada | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	4.1
Canada | Level 1 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	2.4
Canada | Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	5.7
Canada | Level 1 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Canada | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.8
Canada | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Canada | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Canada | Level 2 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Canada | Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Canada | Level 2 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.8
United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	2,431
Net payable	(21.2)
Fair value of Plan Assets	$ 2,409.8
Percentage of Plan Assets	100.00%
Percentage of Plan Asset before net payable	100.90%
United States | Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,503.9	1,354.1	248.7
United States | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 905.9	$ 791.2	$ 70.8
United States | Fixed income | WGL Holdings | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Target asset mix	18.00%
United States | Commingled funds and pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 648.9
Percentage of Plan Asset before net payable	26.90%
United States | Private Equity/Limited Partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 55.6
Percentage of Plan Asset before net payable	2.30%
United States | Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 32
Percentage of Plan Asset before net payable	1.30%
United States | Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 433.8
Percentage of Plan Asset before net payable	18.10%
United States | Collective trust fund | Common stock large cap
Defined Benefit Plan Disclosure
Target asset mix	90.00%
United States | Collective trust fund | Short term money market
Defined Benefit Plan Disclosure
Target asset mix	2.00%
United States | Collective trust fund | Income producing property
Defined Benefit Plan Disclosure
Target asset mix	8.00%
United States | Common stock large cap | WGL Holdings | Defined Benefit
Defined Benefit Plan Disclosure
Target asset mix	58.00%
United States | Corporate bonds | WGL Holdings | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Target asset mix	24.00%
United States | Net payable
Defined Benefit Plan Disclosure
Percentage of Plan Assets payable	(0.90%)
United States | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,260.7
Percentage of Plan Assets	52.30%
United States | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 10.8
Percentage of Plan Assets	0.40%
United States | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2.6
Percentage of Plan Assets	0.10%
United States | Fair value | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 302.5
Percentage of Plan Assets	12.60%
United States | Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 933
Percentage of Plan Assets	38.70%
United States | Fair value | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ (0.2)
Percentage of Plan Assets	0.00%
United States | Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12
Percentage of Plan Assets	0.50%
United States | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 438.8
United States | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	10.8
United States | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	2.6
United States | Level 1 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	302.2
United States | Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	123.2
United States | Level 1 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
United States | Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
United States | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	821.9
United States | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
United States | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
United States | Level 2 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.3
United States | Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	809.8
United States | Level 2 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	(0.2)
United States | Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12

Pension Plans and Retiree Be_13

Pension Plans and Retiree Benefits - Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit
Significant actuarial assumptions used in measuring net benefit plan costs
Average remaining service life of active employees	9 years	9 years 7 months 6 days
Defined Benefit | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	2.90%	3.25%
Expected long-term rate of return on plan assets (percent)	5.75%	3.20%
Rate of compensation increase (percent)	2.75%	2.75%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	2.90%	3.60%
Rate of compensation increase (percent)	2.75%	2.75%
Defined Benefit | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	4.40%	4.30%
Expected long-term rate of return on plan assets (percent)	7.15%	7.60%
Rate of compensation increase (percent)	4.10%	4.10%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	3.50%	4.40%
Rate of compensation increase (percent)	4.00%	4.10%
Post- Retirement Benefits
Significant actuarial assumptions used in measuring net benefit plan costs
Rate of compensation increase (percent)	4.10%	4.10%
Average remaining service life of active employees	13 years 2 months	14 years 1 month 6 days
Significant actuarial assumptions used in measuring benefit obligations
Rate of compensation increase (percent)	3.50%	4.10%
Post- Retirement Benefits | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.90%	3.60%
Expected long-term rate of return on plan assets (percent)	4.66%	3.75%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	3.10%	3.90%
Post- Retirement Benefits | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	4.50%	4.30%
Expected long-term rate of return on plan assets (percent)	7.15%	7.60%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	3.60%	4.50%

Pension Plans and Retiree Be_14

Pension Plans and Retiree Benefits - Summary of Assumed Health Care Cost Trend Rates (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Retirement Benefits [Abstract]
Increase, Service and interest costs	$ 1.9
Decrease, Service and interest costs	(1.5)
Increase, Accrued benefit obligations	22.7
Decrease, Accrued benefit obligation	$ (18.4)

Pension Plans and Retiree Be_15

Pension Plans and Retiree Benefits - Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans (Details) $ in Millions	Dec. 31, 2019CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Expected employer contributions, 2020	$ 37
Expected benefit payments:
2020	104.6
2021	85.1
2022	93.3
2023	90
2024	90.7
2025 - 2028	474.1
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Expected employer contributions, 2020	3.2
Expected benefit payments:
2020	23.8
2021	22.6
2022	22.5
2023	22.3
2024	22.1
2025 - 2028	$ 112.6

Commitments, Guarantees, and _3

Commitments, Guarantees, and Contingencies - Summary of Future Payment Commitments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2017	Dec. 31, 2014hour	Dec. 31, 2019CAD ($)	Dec. 31, 2015
Other Commitments
Operating leases, 2020				$ 27.8
Operating leases, 2021				27.1
Operating leases, 2022				26.5
Operating leases, 2023				24.5
Operating leases, 2024				20.1
Operating leases, 2025 and beyond				100.1
Total lease payments				226.1
Commitments, 2020				3,990.7
Commitments, 2021				3,665.2
Commitments, 2022				3,263.9
Commitments, 2023				2,870.2
Commitments, 2024				2,624.9
Commitments, 2025 and beyond				27,190.1
Commitments				43,605
Capital projects
Other Commitments
Other commitments, 2020				6.9
Other commitments, 2021				0
Other commitments, 2022				0
Other commitments, 2023				0
Other commitments, 2024				0
Other commitments, 2025 and beyond				0
Other commitments				6.9
Environmental
Other Commitments
Other commitments, 2020				6.5
Other commitments, 2021				4.3
Other commitments, 2022				1
Other commitments, 2023				1
Other commitments, 2024				0.6
Other commitments, 2025 and beyond				0.4
Other commitments				13.8
Merger commitments
Other Commitments
Other commitments, 2020				8.2
Other commitments, 2021				3.8
Other commitments, 2022				1.9
Other commitments, 2023				1.9
Other commitments, 2024				1.9
Other commitments, 2025 and beyond				4.3
Other commitments				22
Cumulative expenses incurred but not yet paid	$ 17
Natural Gas
Other Commitments
Purchase obligations, 2020				2,374
Purchase obligations, 2021				2,488.2
Purchase obligations, 2022				2,323.6
Purchase obligations, 2023				2,076.1
Purchase obligations, 2024				1,959.5
Purchase obligations, 2025 and beyond				22,772
Purchase obligations				33,993.4
Natural Gas | Merger commitments
Other Commitments
Other commitments	$ 70
Propane
Other Commitments
Purchase obligations, 2020				220.2
Purchase obligations, 2021				127.2
Purchase obligations, 2022				94.9
Purchase obligations, 2023				86.5
Purchase obligations, 2024				58.4
Purchase obligations, 2025 and beyond				127.1
Purchase obligations				714.3
Electricity purchase
Other Commitments
Purchase obligations, 2020				567.2
Purchase obligations, 2021				318.1
Purchase obligations, 2022				160
Purchase obligations, 2023				56.4
Purchase obligations, 2024				11
Purchase obligations, 2025 and beyond				0.4
Purchase obligations				1,113.1
Service agreements
Other Commitments
Purchase obligations, 2020				58.7
Purchase obligations, 2021				44
Purchase obligations, 2022				28.2
Purchase obligations, 2023				23.4
Purchase obligations, 2024				22.9
Purchase obligations, 2025 and beyond				309.1
Purchase obligations				486.3
Service agreement term, (EOH/CT) | hour			124,000
Service agreement term			25 years
Service agreement payable				167.9
Service agreement payable in five years				45.4
Service agreement payment period	16 years	12 years
Service agreements | Ridley Terminals Inc.
Other Commitments
Lease term (years)					20 years
Pipeline and storage services
Other Commitments
Purchase obligations, 2020				721.2
Purchase obligations, 2021				652.5
Purchase obligations, 2022				627.8
Purchase obligations, 2023				600.4
Purchase obligations, 2024				550.5
Purchase obligations, 2025 and beyond				3,876.7
Purchase obligations				$ 7,029.1
Electricity, renewable energy credits
Other Commitments
Purchase obligations	$ 17.4
Leak mitigation | Merger commitments
Other Commitments
Other commitments, 2022	8
Other commitments, 2024	$ 2

Commitments, Guarantees, and _4

Commitments, Guarantees, and Contingencies - Narrative (Details)	1 Months Ended
	Jun. 30, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Apr. 23, 2019action	Dec. 31, 2018CAD ($)
Commitments, Contingencies And Guaranteed [Line Items]
Guarantee obligations			$ 0
Other long term receivables			$ 33,100,000		$ 0
Antero Contract
Commitments, Contingencies And Guaranteed [Line Items]
Damages awarded	$ 96,000,000
Antero Contract | WGL Holdings
Commitments, Contingencies And Guaranteed [Line Items]
Adjustments to working capital	45,000,000
Antero Contract | Washington Gas
Commitments, Contingencies And Guaranteed [Line Items]
Damages awarded	$ 11,000,000
Silver Spring Maryland Incident
Commitments, Contingencies And Guaranteed [Line Items]
Number of civil actions | action				37
Loss accural		$ 300,000
Recommended daily fine		25,000
Minimum | Silver Spring Maryland Incident
Commitments, Contingencies And Guaranteed [Line Items]
Estimated penalties		32,000,000
Maximum | Silver Spring Maryland Incident
Commitments, Contingencies And Guaranteed [Line Items]
Estimated penalties		$ 123,300,000

Related Party Transactions - Su

Related Party Transactions - Summary of Related Party Amounts Included in Balance Sheets (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction
Due from related parties, Accounts receivable	$ 17,800,000	$ 60,800,000
Due from related parties, Long-term investments and other assets	45,000,000	45,000,000
Due from related parties	62,800,000	105,800,000
Due to related parties, Accounts payable	2,700,000	6,300,000
Due to related parties, Risk management liabilities - current	0	900,000
Due to related parties	2,700,000	7,200,000
Petrogas | AltaGas
Related Party Transaction
Due from related parties, Long-term investments and other assets	45,000,000	$ 45,000,000
Credit facility maximum borrowing capacity	100,000,000
Committed amount	$ 50,000,000

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction
Revenue	$ 114.9	$ 68.4
Cost of sales	12.8	4.2
Operating and administrative recoveries	(1.8)	(1.3)
Other income	$ 3.2	9.2
Unrealized Loss On Foreign Exchange Hedge With ACI
Related Party Transaction
Revenue		$ 0.2

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Schedule of Changes in Operating Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Accounts receivable	$ 168.4	$ (526.9)
Inventory	(2.1)	(100.8)
Other current assets	(85.5)	12.5
Regulatory assets - current	7.1	(15.8)
Accounts payable and accrued liabilities	(280.2)	237.9
Customer deposits	(16.9)	(13.3)
Regulatory liabilities - current	34.2	69.2
Risk management liabilities - current	1.1	0
Other current liabilities	(5.6)	(5.9)
Other operating assets and liabilities	(52)	(143.4)
Changes in operating assets and liabilities	$ (231.5)	$ (486.5)

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information - Schedule of Supplemental Cash Payments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Interest paid (net of capitalized interest)	$ 351.7	$ 288.9
Income taxes paid	$ 67.2	$ 36.9

- Reconciliation of Cash and Re

- Reconciliation of Cash and Restricted Cash Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 57.1	$ 101.6
Restricted cash holdings from customers - current	4	4.1
Restricted cash holdings from customers - non-current	3.9	6.1
Restricted cash included in prepaid expenses and other current assets	25.4	27.6
Restricted cash included in long-term investments and other assets	32	61.7
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$ 122.4	$ 201.1	$ 43.7

Segmented Information - Narrati

Segmented Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2019segment
Segment Reporting [Abstract]
Number of reporting segments	4

Segmented Information - Reconci

Segmented Information - Reconciliation Of Segment Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues	$ 5,495	$ 4,256.7
Utilities
Revenues	2,564.2	1,752.6
Midstream
Revenues	1,574.3	1,344.6
Power
Revenues	1,356.3	1,162
Corporate
Revenues	0.2	(2.5)
Operating Segments
Revenues	5,539.4	4,369.2
Operating Segments | Utilities
Revenues	2,590.8	1,765.6
Operating Segments | Midstream
Revenues	1,581.2	1,435
Operating Segments | Power
Revenues	1,367.2	1,171
Operating Segments | Corporate
Revenues	0.2	(2.4)
Intersegment revenue
Revenues	(44.4)	(112.5)
Intersegment revenue | Utilities
Revenues	(26.6)	(13)
Intersegment revenue | Midstream
Revenues	(6.9)	(90.4)
Intersegment revenue | Power
Revenues	(10.9)	(9)
Intersegment revenue | Corporate
Revenues	$ 0	$ (0.1)

Segmented Information - Geograp

Segmented Information - Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues from External Customers and Long-Lived Assets
Revenues	$ 5,570.3	$ 4,179.8
Property, plant and equipment	10,125.5	10,929.6
Canada
Revenues from External Customers and Long-Lived Assets
Revenues	1,244.8	1,626.8
Property, plant and equipment	2,682.2	2,348.2
United States
Revenues from External Customers and Long-Lived Assets
Revenues	4,325.5	2,553
Property, plant and equipment	$ 7,443.3	$ 8,581.4

Segmented Information - Schedul

Segmented Information - Schedule of Segment Composition (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information
Revenues	$ 5,495	$ 4,256.7
Cost of sales	(3,227.1)	(2,455.3)
Operating and administrative	(1,298.7)	(1,129)
Accretion expenses	(5.1)	(10.9)
Depreciation and amortization	(438)	(394)
Provision on assets (note 6)	(415.8)	(728.7)
Income (loss) from equity investments	141.1	47.9
Other income (loss)	908.1	0.9
Foreign exchange gains (losses)	(1)	4.5
Interest expense	(345.8)	(309)
Income (loss) before income taxes	812.7	(716.9)
Net additions (reductions) to property, plant and equipment	(1,090.2)	572.5
Net additions (reductions) to intangible assets	36.5	45.7
Utilities
Segment Reporting Information
Revenues	2,564.2	1,752.6
Provision on assets (note 6)	0	(193.7)
Midstream
Segment Reporting Information
Revenues	1,574.3	1,344.6
Power
Segment Reporting Information
Revenues	1,356.3	1,162
Provision on assets (note 6)	(380.6)	(381.3)
Corporate
Segment Reporting Information
Revenues	0.2	(2.5)
Operating Segments
Segment Reporting Information
Revenues	5,539.4	4,369.2
Operating Segments | Utilities
Segment Reporting Information
Revenues	2,590.8	1,765.6
Cost of sales	(1,117.9)	(838.3)
Operating and administrative	(860.7)	(727.4)
Accretion expenses	(0.1)	(0.1)
Depreciation and amortization	(261.6)	(165.8)
Provision on assets (note 6)	0	(193.7)
Income (loss) from equity investments	18.3	7.2
Other income (loss)	27	4.5
Foreign exchange gains (losses)	0	0
Interest expense	0	(103.9)
Income (loss) before income taxes	395.8	(251.9)
Net additions (reductions) to property, plant and equipment	839.6	507
Net additions (reductions) to intangible assets	22.6	21.8
Operating Segments | Midstream
Segment Reporting Information
Revenues	1,581.2	1,435
Cost of sales	(1,057.7)	(976.4)
Operating and administrative	(249.1)	(201.7)
Accretion expenses	(3.9)	(4)
Depreciation and amortization	(92.1)	(84.4)
Provision on assets (note 6)	(35.2)	(153.7)
Income (loss) from equity investments	122.4	51.1
Other income (loss)	28.7	0.7
Foreign exchange gains (losses)	(4.5)	(0.2)
Interest expense	0	(10.6)
Income (loss) before income taxes	289.8	55.8
Net additions (reductions) to property, plant and equipment	350.3	383.4
Net additions (reductions) to intangible assets	4.9	4.7
Operating Segments | Power
Segment Reporting Information
Revenues	1,367.2	1,171
Cost of sales	(1,084.4)	(743.7)
Operating and administrative	(159.8)	(159.1)
Accretion expenses	(1.1)	(6.8)
Depreciation and amortization	(72.3)	(130.5)
Provision on assets (note 6)	(380.6)	(381.3)
Income (loss) from equity investments	0.4	(10.4)
Other income (loss)	853.8	(5.9)
Foreign exchange gains (losses)	0	(0.1)
Interest expense	0	(8.9)
Income (loss) before income taxes	523.2	(275.7)
Net additions (reductions) to property, plant and equipment	(2,281.3)	(321.9)
Net additions (reductions) to intangible assets	0	12.5
Operating Segments | Corporate
Segment Reporting Information
Revenues	0.2	(2.4)
Cost of sales	0	0
Operating and administrative	(40.6)	(50.6)
Accretion expenses	0	0
Depreciation and amortization	(12)	(13.3)
Provision on assets (note 6)	0	0
Income (loss) from equity investments	0	0
Other income (loss)	(1.4)	2
Foreign exchange gains (losses)	3.5	4.8
Interest expense	(345.8)	(185.6)
Income (loss) before income taxes	(396.1)	(245.1)
Net additions (reductions) to property, plant and equipment	1.2	4
Net additions (reductions) to intangible assets	9	6.7
Intersegment Elimination
Segment Reporting Information
Revenues	(44.4)	(112.5)
Cost of sales	32.9	103.1
Operating and administrative	11.5	9.8
Accretion expenses	0	0
Depreciation and amortization	0	0
Provision on assets (note 6)	0	0
Income (loss) from equity investments	0	0
Other income (loss)	0	(0.4)
Foreign exchange gains (losses)	0	0
Interest expense	0	0
Income (loss) before income taxes	0	0
Net additions (reductions) to property, plant and equipment	0	0
Net additions (reductions) to intangible assets	0	0
Intersegment Elimination | Utilities
Segment Reporting Information
Revenues	(26.6)	(13)
Intersegment Elimination | Midstream
Segment Reporting Information
Revenues	(6.9)	(90.4)
Intersegment Elimination | Power
Segment Reporting Information
Revenues	(10.9)	(9)
Intersegment Elimination | Corporate
Segment Reporting Information
Revenues	$ 0	$ (0.1)

Segmented Information - Sched_2

Segmented Information - Schedule of Goodwill and Total Assets by Segment (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information
Goodwill (note 11)	$ 3,942.1	$ 4,068.2	$ 817.3
Segmented assets	19,794.5	23,487.7
Operating Segments | Utilities
Segment Reporting Information
Goodwill (note 11)	3,573	3,450.8
Segmented assets	13,097.1	12,991.3
Operating Segments | Midstream
Segment Reporting Information
Goodwill (note 11)	246.5	426.4
Segmented assets	5,471.4	6,398.8
Operating Segments | Power
Segment Reporting Information
Goodwill (note 11)	122.6	191
Segmented assets	1,019.9	3,814.7
Operating Segments | Corporate
Segment Reporting Information
Goodwill (note 11)	0	0
Segmented assets	$ 206.1	$ 282.9

Subsequent Events (Details)

Subsequent Events (Details) - CAD ($)	Feb. 27, 2020	Jan. 02, 2020	Dec. 31, 2019	Dec. 31, 2018
Subsequent Event
Equity method investment			$ 1,461,600,000	$ 2,392,400,000
Subsequent Event | AIJVLP
Subsequent Event
Controlling interest (percent)		50.00%
Subsequent Event | Constitution Pipeline
Subsequent Event
Equity method investment, ownership interest (percent)	10.00%
Equity method investment	$ 0
Subsequent Event | Idemitsu | AIJVLP
Subsequent Event
Controlling interest (percent)		50.00%
Subsequent Event | SAM | Petrogas
Subsequent Event
Noncontrolling ownership interest (percent)		33.00%

Uncategorized Items - cik000169

Label	Element	Value
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (7,100,000)